System and method of controlling combustion and emissions in gas turbine engine with exhaust gas recirculation

ABSTRACT

In one embodiment, a system includes a turbine combustor having a combustor liner disposed about a combustion chamber, a head end upstream of the combustion chamber relative to a downstream direction of a flow of combustion gases through the combustion chamber, a flow sleeve disposed at an offset about the combustor liner to define a passage, and a barrier within the passage. The head end is configured to direct an oxidant flow and a first fuel flow toward the combustion chamber. The passage is configured to direct a gas flow toward the head end and to direct a portion of the oxidant flow toward a turbine end of the turbine combustor. The gas flow includes a substantially inert gas. The barrier is configured to block the portion of the oxidant flow toward the turbine end and to block the gas flow toward the head end within the passage.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to and benefit of U.S. ProvisionalPatent Application No. 61/860,214, entitled “SYSTEM AND METHOD OFCONTROLLING COMBUSTION AND EMISSIONS IN GAS TURBINE ENGINE WITH EXHAUSTGAS RECIRCULATION,” filed Jul. 30, 2013, which is hereby incorporated byreference in its entirety for all purposes.

BACKGROUND

The subject matter disclosed herein relates to gas turbines, and morespecifically, to gas turbines with exhaust gas recirculation.

Gas turbine engines are used in a wide variety of applications, such aspower generation, aircraft, and various machinery. Gas turbine enginesgenerally combust a fuel with an oxidant (e.g., air) in a combustorsection to generate hot combustion gases, which then drive one or moreturbine stages of a turbine section. In turn, the turbine section drivesone or more compressor stages of a compressor section, therebycompressing oxidant for intake into the combustor section along with thefuel. Again, the fuel and oxidant mix in the combustor section, and thencombust to produce the hot combustion gases. Unfortunately, certaincomponents of the combustor section are exposed to high temperatures,which may reduce the life of the components. Furthermore, cooling thecomponents or combustion gases with oxidant may increase theconcentrations of oxidant in the exhaust gas.

BRIEF DESCRIPTION

Certain embodiments commensurate in scope with the originally claimedinvention are summarized below. These embodiments are not intended tolimit the scope of the claimed invention, but rather these embodimentsare intended only to provide a brief summary of possible forms of theinvention. Indeed, the invention may encompass a variety of forms thatmay be similar to or different from the embodiments set forth below.

In one embodiment, a system includes a turbine combustor having acombustor liner disposed about a combustion chamber, a head end upstreamof the combustion chamber relative to a downstream direction of a flowof combustion gases through the combustion chamber, a flow sleevedisposed at an offset about the combustor liner to define a passage, anda barrier within the passage. The head end is configured to direct anoxidant flow and a first fuel flow toward the combustion chamber. Thepassage is configured to direct a gas flow toward the head end and todirect a portion of the oxidant flow toward a turbine end of the turbinecombustor. The gas flow includes a substantially inert gas. The barrieris configured to block the portion of the oxidant flow toward theturbine end and to block the gas flow toward the head end within thepassage.

In another embodiment, a system includes a turbine combustor having acombustor liner disposed about a combustion chamber and a flow sleevedisposed at an offset about the combustor liner to define a passage. Thepassage includes an oxidant section configured to direct an oxidant in afirst direction to react with a first fuel in the combustion chamber toproduce combustion gases. The passage also includes a cooling sectionconfigured to direct an inert gas in a second direction substantiallyopposite to the first direction. The inert gas is configured to cool thecombustor liner and the combustion gases in the combustion chamber. Thepassage also includes a barrier section between the oxidant section andthe cooling section. The barrier section is configured to substantiallyseparate the oxidant in the oxidant section from the inert gas in thecooling section.

In another embodiment, a method includes injecting an oxidant and fuelinto a combustion chamber from a head end of a turbine combustor,combusting the oxidant and the fuel in the combustion chamber to providesubstantially stoichiometric combustion, and cooling the combustionchamber with an exhaust gas flow. The exhaust gas flow is directedupstream from a turbine end of the turbine combustor toward the head endalong a passage disposed about the combustion chamber. The method alsoincludes blocking the exhaust gas flow within the passage with abarrier. The barrier includes a dynamic barrier, a physical barrier, orany combination thereof.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features, aspects, and advantages of the presentinvention will become better understood when the following detaileddescription is read with reference to the accompanying drawings in whichlike characters represent like parts throughout the drawings, wherein:

FIG. 1 is a diagram of an embodiment of a system having a turbine-basedservice system coupled to a hydrocarbon production system;

FIG. 2 is a diagram of an embodiment of the system of FIG. 1, furtherillustrating a control system and a combined cycle system;

FIG. 3 is a diagram of an embodiment of the system of FIGS. 1 and 2,further illustrating details of a gas turbine engine, exhaust gas supplysystem, and exhaust gas processing system;

FIG. 4 is a flow chart of an embodiment of a process for operating thesystem of FIGS. 1-3;

FIG. 5 is a schematic diagram of an embodiment of a combustor section ofa gas turbine engine with exhaust gas recirculation and a barriersection within a flow sleeve;

FIG. 6 is a schematic diagram of an embodiment of a combustor section ofthe gas turbine engine of FIG. 5 with a dynamic barrier within thebarrier section;

FIG. 7 is a schematic diagram of an embodiment of a combustor section ofthe gas turbine engine of FIG. 5 with a physical barrier within thebarrier section;

FIG. 8 is a cross-sectional view of an embodiment of a turbine combustortaken along line 8-8 of FIG. 7; and

FIG. 9 is a cross-sectional view of an embodiment of a turbine combustortaken along line 8-8 of FIG. 7.

DETAILED DESCRIPTION

One or more specific embodiments of the present invention will bedescribed below. In an effort to provide a concise description of theseembodiments, all features of an actual implementation may not bedescribed in the specification. It should be appreciated that in thedevelopment of any such actual implementation, as in an engineering ordesign project, numerous implementation-specific decisions are made toachieve the specific goals, such as compliance with system-relatedand/or business-related constraints, which may vary from oneimplementation to another. Moreover, it should be appreciated that sucheffort might be complex and time consuming, but would nevertheless be aroutine undertaking of design, fabrication, and manufacture for those ofordinary skill having the benefit of this disclosure.

Detailed example embodiments are disclosed herein. However, specificstructural and functional details disclosed herein are merelyrepresentative for purposes of describing example embodiments.Embodiments of the present invention may, however, be embodied in manyalternate forms, and should not be construed as limited to only theembodiments set forth herein.

Accordingly, while example embodiments are capable of variousmodifications and alternative forms, embodiments thereof are illustratedby way of example in the figures and will herein be described in detail.It should be understood, however, that there is no intent to limitexample embodiments to the particular forms disclosed, but to thecontrary, example embodiments are to cover all modifications,equivalents, and alternatives falling within the scope of the presentinvention.

The terminology used herein is for describing particular embodimentsonly and is not intended to be limiting of example embodiments. As usedherein, the singular forms “a”, “an” and “the” are intended to includethe plural forms as well, unless the context clearly indicatesotherwise. The terms “comprises”, “comprising”, “includes” and/or“including”, when used herein, specify the presence of stated features,integers, steps, operations, elements, and/or components, but do notpreclude the presence or addition of one or more other features,integers, steps, operations, elements, components, and/or groupsthereof.

Although the terms first, second, primary, secondary, etc. may be usedherein to describe various elements, these elements should not belimited by these terms. These terms are only used to distinguish oneelement from another. For example, but not limiting to, a first elementcould be termed a second element, and, similarly, a second element couldbe termed a first element, without departing from the scope of exampleembodiments. As used herein, the term “and/or” includes any, and all,combinations of one or more of the associated listed items.

Certain terminology may be used herein for the convenience of the readeronly and is not to be taken as a limitation on the scope of theinvention. For example, words such as “upper”, “lower”, “left”, “right”,“front”, “rear”, “top”, “bottom”, “horizontal”, “vertical”, “upstream”,“downstream”, “fore”, “aft”, and the like; merely describe theconfiguration shown in the figures. Indeed, the element or elements ofan embodiment of the present invention may be oriented in any directionand the terminology, therefore, should be understood as encompassingsuch variations unless specified otherwise.

As discussed in detail below, the disclosed embodiments relate generallyto gas turbine systems with exhaust gas recirculation (EGR), andparticularly stoichiometric operation of the gas turbine systems usingEGR. For example, the gas turbine systems may be configured torecirculate the exhaust gas along an exhaust recirculation path,stoichiometrically combust fuel and oxidant along with at least some ofthe recirculated exhaust gas, and capture the exhaust gas for use invarious target systems. The recirculation of the exhaust gas along withstoichiometric combustion may help to increase the concentration levelof carbon dioxide (CO₂) in the exhaust gas, which can then be posttreated to separate and purify the CO₂ and nitrogen (N₂) for use invarious target systems. The gas turbine systems also may employ variousexhaust gas processing (e.g., heat recovery, catalyst reactions, etc.)along the exhaust recirculation path, thereby increasing theconcentration level of CO₂, reducing concentration levels of otheremissions (e.g., carbon monoxide, nitrogen oxides, and unburnthydrocarbons), and increasing energy recovery (e.g., with heat recoveryunits). Furthermore, the gas turbine engines may be configured tocombust the fuel and oxidant with one or more diffusion flames (e.g.,using diffusion fuel nozzles), premix flames (e.g., using premix fuelnozzles), or any combination thereof. In certain embodiments, thediffusion flames may help to maintain stability and operation withincertain limits for stoichiometric combustion, which in turn helps toincrease production of CO₂. For example, a gas turbine system operatingwith diffusion flames may enable a greater quantity of EGR, as comparedto a gas turbine system operating with premix flames. In turn, theincreased quantity of EGR helps to increase CO₂ production. Possibletarget systems include pipelines, storage tanks, carbon sequestrationsystems, and hydrocarbon production systems, such as enhanced oilrecovery (EOR) systems.

Some embodiments of a stoichiometric exhaust gas recirculation (SEGR)gas turbine system, as described below, may supply the oxidant and thefuel into a combustion chamber from a head end portion of a combustor,and separately supply an inert gas (e.g., exhaust gas) to the combustorat an opposite turbine end portion of the combustor to cool thecombustor liner and combustion gases within the combustion chamber. Abarrier (e.g., physical barrier, partial physical barrier, dynamicbarrier) in a passage along the combustor liner may separate the oxidantand the inert gas outside of the combustion chamber. In someembodiments, the combustor may have differentially supplied andcontrolled sets of fuel nozzles to inject the oxidant and one or morefuels into the combustion chamber. The oxidant and the inert gas mayflow through the passage in opposite directions. The oxidant and theinert gas may not mix upstream of the flame (e.g., combustion reaction)within the combustion chamber. In some embodiments, the oxidant isconcentrated near the flame zone to increase the efficiency ofcombustion, thereby affecting the equivalence ratio. Adjusting theequivalence ratio to approximately 1.0 (e.g., between 0.95 and 1.05) mayreduce the concentrations of oxidant, fuel, and/or other components(e.g., nitrogen oxides, water) within the exhaust gases of the SEGR gasturbine system. However, the combustion temperature also may be greaterat an equivalence ratio at or near 1.0 (e.g., substantiallystoichiometric combustion). The greater combustion temperature maycreate greater emissions, such as nitrogen oxide (NO_(x)) emissions. Theinert gas (e.g., exhaust gas) may be a heat sink for the combustorand/or combustion gases. In other words, the inert gas (e.g., exhaustgas) may help to reduce the temperature of combustion gases, therebyreducing the NO emissions without introducing more oxidant (e.g.,oxygen) into the combustion gases. In some embodiments, adjusting theequivalence ratio to approximately 1.0 may increase the concentration ofcarbon dioxide that may be utilized in an enhanced oil recovery system,while the use of exhaust gas as the diluent maintains low levels ofNO_(x), oxygen, and fuel in the combustion gases. The exhaust gas, orthe carbon dioxide extracted from the exhaust gas, may be utilized by afluid injection system for enhanced oil recovery.

FIG. 1 is a diagram of an embodiment of a system 10 having a hydrocarbonproduction system 12 associated with a turbine-based service system 14.As discussed in further detail below, various embodiments of theturbine-based service system 14 are configured to provide variousservices, such as electrical power, mechanical power, and fluids (e.g.,exhaust gas), to the hydrocarbon production system 12 to facilitate theproduction or retrieval of oil and/or gas. In the illustratedembodiment, the hydrocarbon production system 12 includes an oil/gasextraction system 16 and an enhanced oil recovery (EOR) system 18, whichare coupled to a subterranean reservoir 20 (e.g., an oil, gas, orhydrocarbon reservoir). The oil/gas extraction system 16 includes avariety of surface equipment 22, such as a Christmas tree or productiontree 24, coupled to an oil/gas well 26. Furthermore, the well 26 mayinclude one or more tubulars 28 extending through a drilled bore 30 inthe earth 32 to the subterranean reservoir 20. The tree 24 includes oneor more valves, chokes, isolation sleeves, blowout preventers, andvarious flow control devices, which regulate pressures and control flowsto and from the subterranean reservoir 20. While the tree 24 isgenerally used to control the flow of the production fluid (e.g., oil orgas) out of the subterranean reservoir 20, the EOR system 18 mayincrease the production of oil or gas by injecting one or more fluidsinto the subterranean reservoir 20.

Accordingly, the EOR system 18 may include a fluid injection system 34,which has one or more tubulars 36 extending through a bore 38 in theearth 32 to the subterranean reservoir 20. For example, the EOR system18 may route one or more fluids 40, such as gas, steam, water,chemicals, or any combination thereof, into the fluid injection system34. For example, as discussed in further detail below, the EOR system 18may be coupled to the turbine-based service system 14, such that thesystem 14 routes an exhaust gas 42 (e.g., substantially or entirely freeof oxygen) to the EOR system 18 for use as the injection fluid 40. Thefluid injection system 34 routes the fluid 40 (e.g., the exhaust gas 42)through the one or more tubulars 36 into the subterranean reservoir 20,as indicated by arrows 44. The injection fluid 40 enters thesubterranean reservoir 20 through the tubular 36 at an offset distance46 away from the tubular 28 of the oil/gas well 26. Accordingly, theinjection fluid 40 displaces the oil/gas 48 disposed in the subterraneanreservoir 20, and drives the oil/gas 48 up through the one or moretubulars 28 of the hydrocarbon production system 12, as indicated byarrows 50. As discussed in further detail below, the injection fluid 40may include the exhaust gas 42 originating from the turbine-basedservice system 14, which is able to generate the exhaust gas 42 on-siteas needed by the hydrocarbon production system 12. In other words, theturbine-based system 14 may simultaneously generate one or more services(e.g., electrical power, mechanical power, steam, water (e.g.,desalinated water), and exhaust gas (e.g., substantially free ofoxygen)) for use by the hydrocarbon production system 12, therebyreducing or eliminating the reliance on external sources of suchservices.

In the illustrated embodiment, the turbine-based service system 14includes a stoichiometric exhaust gas recirculation (SEGR) gas turbinesystem 52 and an exhaust gas (EG) processing system 54. The gas turbinesystem 52 may be configured to operate in a stoichiometric combustionmode of operation (e.g., a stoichiometric control mode) and anon-stoichiometric combustion mode of operation (e.g., anon-stoichiometric control mode), such as a fuel-lean control mode or afuel-rich control mode. In the stoichiometric control mode, thecombustion generally occurs in a substantially stoichiometric ratio of afuel and oxidant, thereby resulting in substantially stoichiometriccombustion. In particular, stoichiometric combustion generally involvesconsuming substantially all of the fuel and oxidant in the combustionreaction, such that the products of combustion are substantially orentirely free of unburnt fuel and oxidant. One measure of stoichiometriccombustion is the equivalence ratio, or phi (Φ), which is the ratio ofthe actual fuel/oxidant ratio relative to the stoichiometricfuel/oxidant ratio. An equivalence ratio of greater than 1.0 results ina fuel-rich combustion of the fuel and oxidant, whereas an equivalenceratio of less than 1.0 results in a fuel-lean combustion of the fuel andoxidant. In contrast, an equivalence ratio of 1.0 results in combustionthat is neither fuel-rich nor fuel-lean, thereby substantially consumingall of the fuel and oxidant in the combustion reaction. In context ofthe disclosed embodiments, the term stoichiometric or substantiallystoichiometric may refer to an equivalence ratio of approximately 0.95to approximately 1.05. However, the disclosed embodiments may alsoinclude an equivalence ratio of 1.0 plus or minus 0.01, 0.02, 0.03,0.04, 0.05, or more. Again, the stoichiometric combustion of fuel andoxidant in the turbine-based service system 14 may result in products ofcombustion or exhaust gas (e.g., 42) with substantially no unburnt fuelor oxidant remaining. For example, the exhaust gas 42 may have less than1, 2, 3, 4, or 5 percent by volume of oxidant (e.g., oxygen), unburntfuel or hydrocarbons (e.g., HCs), nitrogen oxides (e.g., NO_(X)), carbonmonoxide (CO), sulfur oxides (e.g., SO_(X)), hydrogen, and otherproducts of incomplete combustion. By further example, the exhaust gas42 may have less than approximately 10, 20, 30, 40, 50, 60, 70, 80, 90,100, 200, 300, 400, 500, 1000, 2000, 3000, 4000, or 5000 parts permillion by volume (ppmv) of oxidant (e.g., oxygen), unburnt fuel orhydrocarbons (e.g., HCs), nitrogen oxides (e.g., NO_(X)), carbonmonoxide (CO), sulfur oxides (e.g., SO_(X)), hydrogen, and otherproducts of incomplete combustion. However, the disclosed embodimentsalso may produce other ranges of residual fuel, oxidant, and otheremissions levels in the exhaust gas 42. As used herein, the termsemissions, emissions levels, and emissions targets may refer toconcentration levels of certain products of combustion (e.g., NO_(X),CO, SO_(X), O₂, N₂, H₂, HCs, etc.), which may be present in recirculatedgas streams, vented gas streams (e.g., exhausted into the atmosphere),and gas streams used in various target systems (e.g., the hydrocarbonproduction system 12).

Although the SEGR gas turbine system 52 and the EG processing system 54may include a variety of components in different embodiments, theillustrated EG processing system 54 includes a heat recovery steamgenerator (HRSG) 56 and an exhaust gas recirculation (EGR) system 58,which receive and process an exhaust gas 60 originating from the SEGRgas turbine system 52. The HRSG 56 may include one or more heatexchangers, condensers, and various heat recovery equipment, whichcollectively function to transfer heat from the exhaust gas 60 to astream of water, thereby generating steam 62. The steam 62 may be usedin one or more steam turbines, the EOR system 18, or any other portionof the hydrocarbon production system 12. For example, the HRSG 56 maygenerate low pressure, medium pressure, and/or high pressure steam 62,which may be selectively applied to low, medium, and high pressure steamturbine stages, or different applications of the EOR system 18. Inaddition to the steam 62, a treated water 64, such as a desalinatedwater, may be generated by the HRSG 56, the EGR system 58, and/oranother portion of the EG processing system 54 or the SEGR gas turbinesystem 52. The treated water 64 (e.g., desalinated water) may beparticularly useful in areas with water shortages, such as inland ordesert regions. The treated water 64 may be generated, at least in part,due to the large volume of air driving combustion of fuel within theSEGR gas turbine system 52. While the on-site generation of steam 62 andwater 64 may be beneficial in many applications (including thehydrocarbon production system 12), the on-site generation of exhaust gas42, 60 may be particularly beneficial for the EOR system 18, due to itslow oxygen content, high pressure, and heat derived from the SEGR gasturbine system 52. Accordingly, the HRSG 56, the EGR system 58, and/oranother portion of the EG processing system 54 may output or recirculatean exhaust gas 66 into the SEGR gas turbine system 52, while alsorouting the exhaust gas 42 to the EOR system 18 for use with thehydrocarbon production system 12. Likewise, the exhaust gas 42 may beextracted directly from the SEGR gas turbine system 52 (i.e., withoutpassing through the EG processing system 54) for use in the EOR system18 of the hydrocarbon production system 12.

The exhaust gas recirculation is handled by the EGR system 58 of the EGprocessing system 54. For example, the EGR system 58 includes one ormore conduits, valves, blowers, exhaust gas treatment systems (e.g.,filters, particulate removal units, gas separation units, gaspurification units, heat exchangers, heat recovery units, moistureremoval units, catalyst units, chemical injection units, or anycombination thereof), and controls to recirculate the exhaust gas alongan exhaust gas circulation path from an output (e.g., discharged exhaustgas 60) to an input (e.g., intake exhaust gas 66) of the SEGR gasturbine system 52. In the illustrated embodiment, the SEGR gas turbinesystem 52 intakes the exhaust gas 66 into a compressor section havingone or more compressors, thereby compressing the exhaust gas 66 for usein a combustor section along with an intake of an oxidant 68 and one ormore fuels 70. The oxidant 68 may include ambient air, pure oxygen,oxygen-enriched air, oxygen-reduced air, oxygen-nitrogen mixtures, orany suitable oxidant that facilitates combustion of the fuel 70. Thefuel 70 may include one or more gas fuels, liquid fuels, or anycombination thereof. For example, the fuel 70 may include natural gas,liquefied natural gas (LNG), syngas, methane, ethane, propane, butane,naphtha, kerosene, diesel fuel, ethanol, methanol, biofuel, or anycombination thereof.

The SEGR gas turbine system 52 mixes and combusts the exhaust gas 66,the oxidant 68, and the fuel 70 in the combustor section, therebygenerating hot combustion gases or exhaust gas 60 to drive one or moreturbine stages in a turbine section. In certain embodiments, eachcombustor in the combustor section includes one or more premix fuelnozzles, one or more diffusion fuel nozzles, or any combination thereof.For example, each premix fuel nozzle may be configured to mix theoxidant 68 and the fuel 70 internally within the fuel nozzle and/orpartially upstream of the fuel nozzle, thereby injecting an oxidant-fuelmixture from the fuel nozzle into the combustion zone for a premixedcombustion (e.g., a premixed flame). By further example, each diffusionfuel nozzle may be configured to isolate the flows of oxidant 68 andfuel 70 within the fuel nozzle, thereby separately injecting the oxidant68 and the fuel 70 from the fuel nozzle into the combustion zone fordiffusion combustion (e.g., a diffusion flame). In particular, thediffusion combustion provided by the diffusion fuel nozzles delaysmixing of the oxidant 68 and the fuel 70 until the point of initialcombustion, i.e., the flame region. In embodiments employing thediffusion fuel nozzles, the diffusion flame may provide increased flamestability, because the diffusion flame generally forms at the point ofstoichiometry between the separate streams of oxidant 68 and fuel 70(i.e., as the oxidant 68 and fuel 70 are mixing). In certainembodiments, one or more diluents (e.g., the exhaust gas 60, steam,nitrogen, or another inert gas) may be pre-mixed with the oxidant 68,the fuel 70, or both, in either the diffusion fuel nozzle or the premixfuel nozzle. In addition, one or more diluents (e.g., the exhaust gas60, steam, nitrogen, or another inert gas) may be injected into thecombustor at or downstream from the point of combustion within eachcombustor. The use of these diluents may help temper the flame (e.g.,premix flame or diffusion flame), thereby helping to reduce NO_(X)emissions, such as nitrogen monoxide (NO) and nitrogen dioxide (NO₂).Regardless of the type of flame, the combustion produces hot combustiongases or exhaust gas 60 to drive one or more turbine stages. As eachturbine stage is driven by the exhaust gas 60, the SEGR gas turbinesystem 52 generates a mechanical power 72 and/or an electrical power 74(e.g., via an electrical generator). The system 52 also outputs theexhaust gas 60, and may further output water 64. Again, the water 64 maybe a treated water, such as a desalinated water, which may be useful ina variety of applications on-site or off-site.

Exhaust extraction is also provided by the SEGR gas turbine system 52using one or more extraction points 76. For example, the illustratedembodiment includes an exhaust gas (EG) supply system 78 having anexhaust gas (EG) extraction system 80 and an exhaust gas (EG) treatmentsystem 82, which receive exhaust gas 42 from the extraction points 76,treat the exhaust gas 42, and then supply or distribute the exhaust gas42 to various target systems. The target systems may include the EORsystem 18 and/or other systems, such as a pipeline 86, a storage tank88, or a carbon sequestration system 90. The EG extraction system 80 mayinclude one or more conduits, valves, controls, and flow separations,which facilitate isolation of the exhaust gas 42 from the oxidant 68,the fuel 70, and other contaminants, while also controlling thetemperature, pressure, and flow rate of the extracted exhaust gas 42.The EG treatment system 82 may include one or more heat exchangers(e.g., heat recovery units such as heat recovery steam generators,condensers, coolers, or heaters), catalyst systems (e.g., oxidationcatalyst systems), particulate and/or water removal systems (e.g., gasdehydration units, inertial separators, coalescing filters, waterimpermeable filters, and other filters), chemical injection systems,solvent based treatment systems (e.g., absorbers, flash tanks, etc.),carbon capture systems, gas separation systems, gas purificationsystems, and/or a solvent based treatment system, exhaust gascompressors, any combination thereof. These subsystems of the EGtreatment system 82 enable control of the temperature, pressure, flowrate, moisture content (e.g., amount of water removal), particulatecontent (e.g., amount of particulate removal), and gas composition(e.g., percentage of CO₂, N₂, etc.).

The extracted exhaust gas 42 is treated by one or more subsystems of theEG treatment system 82, depending on the target system. For example, theEG treatment system 82 may direct all or part of the exhaust gas 42through a carbon capture system, a gas separation system, a gaspurification system, and/or a solvent based treatment system, which iscontrolled to separate and purify a carbonaceous gas (e.g., carbondioxide) 92 and/or nitrogen (N₂) 94 for use in the various targetsystems. For example, embodiments of the EG treatment system 82 mayperform gas separation and purification to produce a plurality ofdifferent streams 95 of exhaust gas 42, such as a first stream 96, asecond stream 97, and a third stream 98. The first stream 96 may have afirst composition that is rich in carbon dioxide and/or lean in nitrogen(e.g., a CO₂ rich, N₂ lean stream). The second stream 97 may have asecond composition that has intermediate concentration levels of carbondioxide and/or nitrogen (e.g., intermediate concentration CO₂, N₂stream). The third stream 98 may have a third composition that is leanin carbon dioxide and/or rich in nitrogen (e.g., a CO₂ lean, N₂ richstream). Each stream 95 (e.g., 96, 97, and 98) may include a gasdehydration unit, a filter, a gas compressor, or any combinationthereof, to facilitate delivery of the stream 95 to a target system. Incertain embodiments, the CO₂ rich, N₂ lean stream 96 may have a CO₂purity or concentration level of greater than approximately 70, 75, 80,85, 90, 95, 96, 97, 98, or 99 percent by volume, and a N₂ purity orconcentration level of less than approximately 1, 2, 3, 4, 5, 10, 15,20, 25, or percent by volume. In contrast, the CO₂ lean, N₂ rich stream98 may have a CO₂ purity or concentration level of less thanapproximately 1, 2, 3, 4, 5, 10, 15, 20, 25, or percent by volume, andan N₂ purity or concentration level of greater than approximately 70,75, 80, 85, 90, 95, 96, 97, 98, or 99 percent by volume. Theintermediate concentration CO₂, N₂ stream 97 may have a CO₂ purity orconcentration level and/or a N₂ purity or concentration level of betweenapproximately 30 to 70, 35 to 65, 40 to 60, or 45 to 55 percent byvolume. Although the foregoing ranges are merely non-limiting examples,the CO₂ rich, N₂ lean stream 96 and the CO₂ lean, N₂ rich stream 98 maybe particularly well suited for use with the EOR system 18 and the othersystems 84. However, any of these rich, lean, or intermediateconcentration CO₂ streams 95 may be used, alone or in variouscombinations, with the EOR system 18 and the other systems 84. Forexample, the EOR system 18 and the other systems 84 (e.g., the pipeline86, storage tank 88, and the carbon sequestration system 90) each mayreceive one or more CO₂ rich, N₂ lean streams 96, one or more CO₂ lean,N₂ rich streams 98, one or more intermediate concentration CO₂, N₂streams 97, and one or more untreated exhaust gas 42 streams (i.e.,bypassing the EG treatment system 82).

The EG extraction system 80 extracts the exhaust gas 42 at one or moreextraction points 76 along the compressor section, the combustorsection, and/or the turbine section, such that the exhaust gas 42 may beused in the EOR system 18 and other systems 84 at suitable temperaturesand pressures. The EG extraction system 80 and/or the EG treatmentsystem 82 also may circulate fluid flows (e.g., exhaust gas 42) to andfrom the EG processing system 54. For example, a portion of the exhaustgas 42 passing through the EG processing system 54 may be extracted bythe EG extraction system 80 for use in the EOR system 18 and the othersystems 84. In certain embodiments, the EG supply system 78 and the EGprocessing system 54 may be independent or integral with one another,and thus may use independent or common subsystems. For example, the EGtreatment system 82 may be used by both the EG supply system 78 and theEG processing system 54. Exhaust gas 42 extracted from the EG processingsystem 54 may undergo multiple stages of gas treatment, such as one ormore stages of gas treatment in the EG processing system 54 followed byone or more additional stages of gas treatment in the EG treatmentsystem 82.

At each extraction point 76, the extracted exhaust gas 42 may besubstantially free of oxidant 68 and fuel 70 (e.g., unburnt fuel orhydrocarbons) due to substantially stoichiometric combustion and/or gastreatment in the EG processing system 54. Furthermore, depending on thetarget system, the extracted exhaust gas 42 may undergo furthertreatment in the EG treatment system 82 of the EG supply system 78,thereby further reducing any residual oxidant 68, fuel 70, or otherundesirable products of combustion. For example, either before or aftertreatment in the EG treatment system 82, the extracted exhaust gas 42may have less than 1, 2, 3, 4, or 5 percent by volume of oxidant (e.g.,oxygen), unburnt fuel or hydrocarbons (e.g., HCs), nitrogen oxides(e.g., NO_(X)), carbon monoxide (CO), sulfur oxides (e.g., SO_(X)),hydrogen, and other products of incomplete combustion. By furtherexample, either before or after treatment in the EG treatment system 82,the extracted exhaust gas 42 may have less than approximately 10, 20,30, 40, 50, 60, 70, 80, 90, 100, 200, 300, 400, 500, 1000, 2000, 3000,4000, or 5000 parts per million by volume (ppmv) of oxidant (e.g.,oxygen), unburnt fuel or hydrocarbons (e.g., HCs), nitrogen oxides(e.g., NO_(X)), carbon monoxide (CO), sulfur oxides (e.g., SO_(X)),hydrogen, and other products of incomplete combustion. Thus, the exhaustgas 42 is particularly well suited for use with the EOR system 18.

The EGR operation of the turbine system 52 specifically enables theexhaust extraction at a multitude of locations 76. For example, thecompressor section of the system 52 may be used to compress the exhaustgas 66 without any oxidant 68 (i.e., only compression of the exhaust gas66), such that a substantially oxygen-free exhaust gas 42 may beextracted from the compressor section and/or the combustor section priorto entry of the oxidant 68 and the fuel 70. The extraction points 76 maybe located at interstage ports between adjacent compressor stages, atports along the compressor discharge casing, at ports along eachcombustor in the combustor section, or any combination thereof. Incertain embodiments, the exhaust gas 66 may not mix with the oxidant 68and fuel 70 until it reaches the head end portion and/or fuel nozzles ofeach combustor in the combustor section. Furthermore, one or more flowseparators (e.g., walls, dividers, baffles, or the like) may be used toisolate the oxidant 68 and the fuel 70 from the extraction points 76.With these flow separators, the extraction points 76 may be disposeddirectly along a wall of each combustor in the combustor section.

Once the exhaust gas 66, oxidant 68, and fuel 70 flow through the headend portion (e.g., through fuel nozzles) into the combustion portion(e.g., combustion chamber) of each combustor, the SEGR gas turbinesystem 52 is controlled to provide a substantially stoichiometriccombustion of the exhaust gas 66, oxidant 68, and fuel 70. For example,the system 52 may maintain an equivalence ratio of approximately 0.95 toapproximately 1.05. As a result, the products of combustion of themixture of exhaust gas 66, oxidant 68, and fuel 70 in each combustor issubstantially free of oxygen and unburnt fuel. Thus, the products ofcombustion (or exhaust gas) may be extracted from the turbine section ofthe SEGR gas turbine system 52 for use as the exhaust gas 42 routed tothe EOR system 18. Along the turbine section, the extraction points 76may be located at any turbine stage, such as interstage ports betweenadjacent turbine stages. Thus, using any of the foregoing extractionpoints 76, the turbine-based service system 14 may generate, extract,and deliver the exhaust gas 42 to the hydrocarbon production system 12(e.g., the EOR system 18) for use in the production of oil/gas 48 fromthe subterranean reservoir 20.

FIG. 2 is a diagram of an embodiment of the system 10 of FIG. 1,illustrating a control system 100 coupled to the turbine-based servicesystem 14 and the hydrocarbon production system 12. In the illustratedembodiment, the turbine-based service system 14 includes a combinedcycle system 102, which includes the SEGR gas turbine system 52 as atopping cycle, a steam turbine 104 as a bottoming cycle, and the HRSG 56to recover heat from the exhaust gas 60 to generate the steam 62 fordriving the steam turbine 104. Again, the SEGR gas turbine system 52receives, mixes, and stoichiometrically combusts the exhaust gas 66, theoxidant 68, and the fuel 70 (e.g., premix and/or diffusion flames),thereby producing the exhaust gas 60, the mechanical power 72, theelectrical power 74, and/or the water 64. For example, the SEGR gasturbine system 52 may drive one or more loads or machinery 106, such asan electrical generator, an oxidant compressor (e.g., a main aircompressor), a gear box, a pump, equipment of the hydrocarbon productionsystem 12, or any combination thereof. In some embodiments, themachinery 106 may include other drives, such as electrical motors orsteam turbines (e.g., the steam turbine 104), in tandem with the SEGRgas turbine system 52. Accordingly, an output of the machinery 106driven by the SEGR gas turbines system 52 (and any additional drives)may include the mechanical power 72 and the electrical power 74. Themechanical power 72 and/or the electrical power 74 may be used on-sitefor powering the hydrocarbon production system 12, the electrical power74 may be distributed to the power grid, or any combination thereof. Theoutput of the machinery 106 also may include a compressed fluid, such asa compressed oxidant 68 (e.g., air or oxygen), for intake into thecombustion section of the SEGR gas turbine system 52. Each of theseoutputs (e.g., the exhaust gas 60, the mechanical power 72, theelectrical power 74, and/or the water 64) may be considered a service ofthe turbine-based service system 14.

The SEGR gas turbine system 52 produces the exhaust gas 42, 60, whichmay be substantially free of oxygen, and routes this exhaust gas 42, 60to the EG processing system 54 and/or the EG supply system 78. The EGsupply system 78 may treat and delivery the exhaust gas 42 (e.g.,streams 95) to the hydrocarbon production system 12 and/or the othersystems 84. As discussed above, the EG processing system 54 may includethe HRSG 56 and the EGR system 58. The HRSG 56 may include one or moreheat exchangers, condensers, and various heat recovery equipment, whichmay be used to recover or transfer heat from the exhaust gas 60 to water108 to generate the steam 62 for driving the steam turbine 104. Similarto the SEGR gas turbine system 52, the steam turbine 104 may drive oneor more loads or machinery 106, thereby generating the mechanical power72 and the electrical power 74. In the illustrated embodiment, the SEGRgas turbine system 52 and the steam turbine 104 are arranged in tandemto drive the same machinery 106. However, in other embodiments, the SEGRgas turbine system 52 and the steam turbine 104 may separately drivedifferent machinery 106 to independently generate mechanical power 72and/or electrical power 74. As the steam turbine 104 is driven by thesteam 62 from the HRSG 56, the steam 62 gradually decreases intemperature and pressure. Accordingly, the steam turbine 104recirculates the used steam 62 and/or water 108 back into the HRSG 56for additional steam generation via heat recovery from the exhaust gas60. In addition to steam generation, the HRSG 56, the EGR system 58,and/or another portion of the EG processing system 54 may produce thewater 64, the exhaust gas 42 for use with the hydrocarbon productionsystem 12, and the exhaust gas 66 for use as an input into the SEGR gasturbine system 52. For example, the water 64 may be a treated water 64,such as a desalinated water for use in other applications. Thedesalinated water may be particularly useful in regions of low wateravailability. Regarding the exhaust gas 60, embodiments of the EGprocessing system 54 may be configured to recirculate the exhaust gas 60through the EGR system 58 with or without passing the exhaust gas 60through the HRSG 56.

In the illustrated embodiment, the SEGR gas turbine system 52 has anexhaust recirculation path 110, which extends from an exhaust outlet toan exhaust inlet of the system 52. Along the path 110, the exhaust gas60 passes through the EG processing system 54, which includes the HRSG56 and the EGR system 58 in the illustrated embodiment. The EGR system58 may include one or more conduits, valves, blowers, gas treatmentsystems (e.g., filters, particulate removal units, gas separation units,gas purification units, heat exchangers, heat recovery units such asheat recovery steam generators, moisture removal units, catalyst units,chemical injection units, or any combination thereof) in series and/orparallel arrangements along the path 110. In other words, the EGR system58 may include any flow control components, pressure control components,temperature control components, moisture control components, and gascomposition control components along the exhaust recirculation path 110between the exhaust outlet and the exhaust inlet of the system 52.Accordingly, in embodiments with the HRSG 56 along the path 110, theHRSG 56 may be considered a component of the EGR system 58. However, incertain embodiments, the HRSG 56 may be disposed along an exhaust pathindependent from the exhaust recirculation path 110. Regardless ofwhether the HRSG 56 is along a separate path or a common path with theEGR system 58, the HRSG 56 and the EGR system 58 intake the exhaust gas60 and output either the recirculated exhaust gas 66, the exhaust gas 42for use with the EG supply system 78 (e.g., for the hydrocarbonproduction system 12 and/or other systems 84), or another output ofexhaust gas. Again, the SEGR gas turbine system 52 intakes, mixes, andstoichiometrically combusts the exhaust gas 66, the oxidant 68, and thefuel 70 (e.g., premixed and/or diffusion flames) to produce asubstantially oxygen-free and fuel-free exhaust gas 60 for distributionto the EG processing system 54, the hydrocarbon production system 12, orother systems 84.

As noted above with reference to FIG. 1, the hydrocarbon productionsystem 12 may include a variety of equipment to facilitate the recoveryor production of oil/gas 48 from a subterranean reservoir 20 through anoil/gas well 26. For example, the hydrocarbon production system 12 mayinclude the EOR system 18 having the fluid injection system 34. In theillustrated embodiment, the fluid injection system 34 includes anexhaust gas injection EOR system 112 and a steam injection EOR system114. Although the fluid injection system 34 may receive fluids from avariety of sources, the illustrated embodiment may receive the exhaustgas 42 and the steam 62 from the turbine-based service system 14. Theexhaust gas 42 and/or the steam 62 produced by the turbine-based servicesystem 14 also may be routed to the hydrocarbon production system 12 foruse in other oil/gas systems 116.

The quantity, quality, and flow of the exhaust gas 42 and/or the steam62 may be controlled by the control system 100. The control system 100may be dedicated entirely to the turbine-based service system 14, or thecontrol system 100 may optionally also provide control (or at least somedata to facilitate control) for the hydrocarbon production system 12and/or other systems 84. In the illustrated embodiment, the controlsystem 100 includes a controller 118 having a processor 120, a memory122, a steam turbine control 124, a SEGR gas turbine system control 126,and a machinery control 128. The processor 120 may include a singleprocessor or two or more redundant processors, such as triple redundantprocessors for control of the turbine-based service system 14. Thememory 122 may include volatile and/or non-volatile memory. For example,the memory 122 may include one or more hard drives, flash memory,read-only memory, random access memory, or any combination thereof. Thecontrols 124, 126, and 128 may include software and/or hardwarecontrols. For example, the controls 124, 126, and 128 may includevarious instructions or code stored on the memory 122 and executable bythe processor 120. The control 124 is configured to control operation ofthe steam turbine 104, the SEGR gas turbine system control 126 isconfigured to control the system 52, and the machinery control 128 isconfigured to control the machinery 106. Thus, the controller 118 (e.g.,controls 124, 126, and 128) may be configured to coordinate varioussub-systems of the turbine-based service system 14 to provide a suitablestream of the exhaust gas 42 to the hydrocarbon production system 12.

In certain embodiments of the control system 100, each element (e.g.,system, subsystem, and component) illustrated in the drawings ordescribed herein includes (e.g., directly within, upstream, ordownstream of such element) one or more industrial control features,such as sensors and control devices, which are communicatively coupledwith one another over an industrial control network along with thecontroller 118. For example, the control devices associated with eachelement may include a dedicated device controller (e.g., including aprocessor, memory, and control instructions), one or more actuators,valves, switches, and industrial control equipment, which enable controlbased on sensor feedback 130, control signals from the controller 118,control signals from a user, or any combination thereof. Thus, any ofthe control functionality described herein may be implemented withcontrol instructions stored and/or executable by the controller 118,dedicated device controllers associated with each element, or acombination thereof.

In order to facilitate such control functionality, the control system100 includes one or more sensors distributed throughout the system 10 toobtain the sensor feedback 130 for use in execution of the variouscontrols, e.g., the controls 124, 126, and 128. For example, the sensorfeedback 130 may be obtained from sensors distributed throughout theSEGR gas turbine system 52, the machinery 106, the EG processing system54, the steam turbine 104, the hydrocarbon production system 12, or anyother components throughout the turbine-based service system 14 or thehydrocarbon production system 12. For example, the sensor feedback 130may include temperature feedback, pressure feedback, flow rate feedback,flame temperature feedback, combustion dynamics feedback, intake oxidantcomposition feedback, intake fuel composition feedback, exhaustcomposition feedback, the output level of mechanical power 72, theoutput level of electrical power 74, the output quantity of the exhaustgas 42, 60, the output quantity or quality of the water 64, or anycombination thereof. For example, the sensor feedback 130 may include acomposition of the exhaust gas 42, 60 to facilitate stoichiometriccombustion in the SEGR gas turbine system 52. For example, the sensorfeedback 130 may include feedback from one or more intake oxidantsensors along an oxidant supply path of the oxidant 68, one or moreintake fuel sensors along a fuel supply path of the fuel 70, and one ormore exhaust emissions sensors disposed along the exhaust recirculationpath 110 and/or within the SEGR gas turbine system 52. The intakeoxidant sensors, intake fuel sensors, and exhaust emissions sensors mayinclude temperature sensors, pressure sensors, flow rate sensors, andcomposition sensors. The emissions sensors may includes sensors fornitrogen oxides (e.g., NO_(X) sensors), carbon oxides (e.g., CO sensorsand CO₂ sensors), sulfur oxides (e.g., SO_(X) sensors), hydrogen (e.g.,H₂ sensors), oxygen (e.g., O₂ sensors), unburnt hydrocarbons (e.g., HCsensors), or other products of incomplete combustion, or any combinationthereof.

Using this feedback 130, the control system 100 may adjust (e.g.,increase, decrease, or maintain) the intake flow of exhaust gas 66,oxidant 68, and/or fuel 70 into the SEGR gas turbine system 52 (amongother operational parameters) to maintain the equivalence ratio within asuitable range, e.g., between approximately 0.95 to approximately 1.05,between approximately 0.95 to approximately 1.0, between approximately1.0 to approximately 1.05, or substantially at 1.0. For example, thecontrol system 100 may analyze the feedback 130 to monitor the exhaustemissions (e.g., concentration levels of nitrogen oxides, carbon oxidessuch as CO and CO₂, sulfur oxides, hydrogen, oxygen, unburnthydrocarbons, and other products of incomplete combustion) and/ordetermine the equivalence ratio, and then control one or more componentsto adjust the exhaust emissions (e.g., concentration levels in theexhaust gas 42) and/or the equivalence ratio. The controlled componentsmay include any of the components illustrated and described withreference to the drawings, including but not limited to, valves alongthe supply paths for the oxidant 68, the fuel 70, and the exhaust gas66; an oxidant compressor, a fuel pump, or any components in the EGprocessing system 54; any components of the SEGR gas turbine system 52,or any combination thereof. The controlled components may adjust (e.g.,increase, decrease, or maintain) the flow rates, temperatures,pressures, or percentages (e.g., equivalence ratio) of the oxidant 68,the fuel 70, and the exhaust gas 66 that combust within the SEGR gasturbine system 52. The controlled components also may include one ormore gas treatment systems, such as catalyst units (e.g., oxidationcatalyst units), supplies for the catalyst units (e.g., oxidation fuel,heat, electricity, etc.), gas purification and/or separation units(e.g., solvent based separators, absorbers, flash tanks, etc.), andfiltration units. The gas treatment systems may help reduce variousexhaust emissions along the exhaust recirculation path 110, a vent path(e.g., exhausted into the atmosphere), or an extraction path to the EGsupply system 78.

In certain embodiments, the control system 100 may analyze the feedback130 and control one or more components to maintain or reduce emissionslevels (e.g., concentration levels in the exhaust gas 42, 60, 95) to atarget range, such as less than approximately 10, 20, 30, 40, 50, 100,200, 300, 400, 500, 1000, 2000, 3000, 4000, 5000, or 10000 parts permillion by volume (ppmv). These target ranges may be the same ordifferent for each of the exhaust emissions, e.g., concentration levelsof nitrogen oxides, carbon monoxide, sulfur oxides, hydrogen, oxygen,unburnt hydrocarbons, and other products of incomplete combustion. Forexample, depending on the equivalence ratio, the control system 100 mayselectively control exhaust emissions (e.g., concentration levels) ofoxidant (e.g., oxygen) within a target range of less than approximately10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 250, 500, 750, or 1000 ppmv;carbon monoxide (CO) within a target range of less than approximately20, 50, 100, 200, 500, 1000, 2500, or 5000 ppmv; and nitrogen oxides(NO_(X)) within a target range of less than approximately 50, 100, 200,300, 400, or 500 ppmv. In certain embodiments operating with asubstantially stoichiometric equivalence ratio, the control system 100may selectively control exhaust emissions (e.g., concentration levels)of oxidant (e.g., oxygen) within a target range of less thanapproximately 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100 ppmv; andcarbon monoxide (CO) within a target range of less than approximately500, 1000, 2000, 3000, 4000, or 5000 ppmv. In certain embodimentsoperating with a fuel-lean equivalence ratio (e.g., betweenapproximately 0.95 to 1.0), the control system 100 may selectivelycontrol exhaust emissions (e.g., concentration levels) of oxidant (e.g.,oxygen) within a target range of less than approximately 500, 600, 700,800, 900, 1000, 1100, 1200, 1300, 1400, or 1500 ppmv; carbon monoxide(CO) within a target range of less than approximately 10, 20, 30, 40,50, 60, 70, 80, 90, 100, 150, or 200 ppmv; and nitrogen oxides (e.g.,NO_(X)) within a target range of less than approximately 50, 100, 150,200, 250, 300, 350, or 400 ppmv. The foregoing target ranges are merelyexamples, and are not intended to limit the scope of the disclosedembodiments.

The control system 100 also may be coupled to a local interface 132 anda remote interface 134. For example, the local interface 132 may includea computer workstation disposed on-site at the turbine-based servicesystem 14 and/or the hydrocarbon production system 12. In contrast, theremote interface 134 may include a computer workstation disposedoff-site from the turbine-based service system 14 and the hydrocarbonproduction system 12, such as through an internet connection. Theseinterfaces 132 and 134 facilitate monitoring and control of theturbine-based service system 14, such as through one or more graphicaldisplays of sensor feedback 130, operational parameters, and so forth.

Again, as noted above, the controller 118 includes a variety of controls124, 126, and 128 to facilitate control of the turbine-based servicesystem 14. The steam turbine control 124 may receive the sensor feedback130 and output control commands to facilitate operation of the steamturbine 104. For example, the steam turbine control 124 may receive thesensor feedback 130 from the HRSG 56, the machinery 106, temperature andpressure sensors along a path of the steam 62, temperature and pressuresensors along a path of the water 108, and various sensors indicative ofthe mechanical power 72 and the electrical power 74. Likewise, the SEGRgas turbine system control 126 may receive sensor feedback 130 from oneor more sensors disposed along the SEGR gas turbine system 52, themachinery 106, the EG processing system 54, or any combination thereof.For example, the sensor feedback 130 may be obtained from temperaturesensors, pressure sensors, clearance sensors, vibration sensors, flamesensors, fuel composition sensors, exhaust gas composition sensors, orany combination thereof, disposed within or external to the SEGR gasturbine system 52. Finally, the machinery control 128 may receive sensorfeedback 130 from various sensors associated with the mechanical power72 and the electrical power 74, as well as sensors disposed within themachinery 106. Each of these controls 124, 126, and 128 uses the sensorfeedback 130 to improve operation of the turbine-based service system14.

In the illustrated embodiment, the SEGR gas turbine system control 126may execute instructions to control the quantity and quality of theexhaust gas 42, 60, 95 in the EG processing system 54, the EG supplysystem 78, the hydrocarbon production system 12, and/or the othersystems 84. For example, the SEGR gas turbine system control 126 maymaintain a level of oxidant (e.g., oxygen) and/or unburnt fuel in theexhaust gas 60 below a threshold suitable for use with the exhaust gasinjection EOR system 112. In certain embodiments, the threshold levelsmay be less than 1, 2, 3, 4, or 5 percent of oxidant (e.g., oxygen)and/or unburnt fuel by volume of the exhaust gas 42, 60; or thethreshold levels of oxidant (e.g., oxygen) and/or unburnt fuel (andother exhaust emissions) may be less than approximately 10, 20, 30, 40,50, 60, 70, 80, 90, 100, 200, 300, 400, 500, 1000, 2000, 3000, 4000, or5000 parts per million by volume (ppmv) in the exhaust gas 42, 60. Byfurther example, in order to achieve these low levels of oxidant (e.g.,oxygen) and/or unburnt fuel, the SEGR gas turbine system control 126 maymaintain an equivalence ratio for combustion in the SEGR gas turbinesystem 52 between approximately 0.95 and approximately 1.05. The SEGRgas turbine system control 126 also may control the EG extraction system80 and the EG treatment system 82 to maintain the temperature, pressure,flow rate, and gas composition of the exhaust gas 42, 60, 95 withinsuitable ranges for the exhaust gas injection EOR system 112, thepipeline 86, the storage tank 88, and the carbon sequestration system90. As discussed above, the EG treatment system 82 may be controlled topurify and/or separate the exhaust gas 42 into one or more gas streams95, such as the CO₂ rich, N₂ lean stream 96, the intermediateconcentration CO₂, N₂ stream 97, and the CO₂ lean, N₂ rich stream 98. Inaddition to controls for the exhaust gas 42, 60, and 95, the controls124, 126, and 128 may execute one or more instructions to maintain themechanical power 72 within a suitable power range, or maintain theelectrical power 74 within a suitable frequency and power range.

FIG. 3 is a diagram of embodiment of the system 10, further illustratingdetails of the SEGR gas turbine system 52 for use with the hydrocarbonproduction system 12 and/or other systems 84. In the illustratedembodiment, the SEGR gas turbine system 52 includes a gas turbine engine150 coupled to the EG processing system 54. The illustrated gas turbineengine 150 includes a compressor section 152, a combustor section 154,and an expander section or turbine section 156. The compressor section152 includes one or more exhaust gas compressors or compressor stages158, such as 1 to 20 stages of rotary compressor blades disposed in aseries arrangement. Likewise, the combustor section 154 includes one ormore combustors 160, such as 1 to 20 combustors 160 distributedcircumferentially about a rotational axis 162 of the SEGR gas turbinesystem 52. Furthermore, each combustor 160 may include one or more fuelnozzles 164 configured to inject the exhaust gas 66, the oxidant 68,and/or the fuel 70. For example, a head end portion 166 of eachcombustor 160 may house 1, 2, 3, 4, 5, 6, or more fuel nozzles 164,which may inject streams or mixtures of the exhaust gas 66, the oxidant68, and/or the fuel 70 into a combustion portion 168 (e.g., combustionchamber) of the combustor 160.

The fuel nozzles 164 may include any combination of premix fuel nozzles164 (e.g., configured to premix the oxidant 68 and fuel 70 forgeneration of an oxidant/fuel premix flame) and/or diffusion fuelnozzles 164 (e.g., configured to inject separate flows of the oxidant 68and fuel 70 for generation of an oxidant/fuel diffusion flame).Embodiments of the premix fuel nozzles 164 may include swirl vanes,mixing chambers, or other features to internally mix the oxidant 68 andfuel 70 within the nozzles 164, prior to injection and combustion in thecombustion chamber 168. The premix fuel nozzles 164 also may receive atleast some partially mixed oxidant 68 and fuel 70. In certainembodiments, each diffusion fuel nozzle 164 may isolate flows of theoxidant 68 and the fuel 70 until the point of injection, while alsoisolating flows of one or more diluents (e.g., the exhaust gas 66,steam, nitrogen, or another inert gas) until the point of injection. Inother embodiments, each diffusion fuel nozzle 164 may isolate flows ofthe oxidant 68 and the fuel 70 until the point of injection, whilepartially mixing one or more diluents (e.g., the exhaust gas 66, steam,nitrogen, or another inert gas) with the oxidant 68 and/or the fuel 70prior to the point of injection. In addition, one or more diluents(e.g., the exhaust gas 66, steam, nitrogen, or another inert gas) may beinjected into the combustor (e.g., into the hot products of combustion)either at or downstream from the combustion zone, thereby helping toreduce the temperature of the hot products of combustion and reduceemissions of NO_(X) (e.g., NO and NO₂). Regardless of the type of fuelnozzle 164, the SEGR gas turbine system 52 may be controlled to providesubstantially stoichiometric combustion of the oxidant 68 and fuel 70.

In diffusion combustion embodiments using the diffusion fuel nozzles164, the fuel 70 and oxidant 68 generally do not mix upstream from thediffusion flame, but rather the fuel 70 and oxidant 68 mix and reactdirectly at the flame surface and/or the flame surface exists at thelocation of mixing between the fuel 70 and oxidant 68. In particular,the fuel 70 and oxidant 68 separately approach the flame surface (ordiffusion boundary/interface), and then diffuse (e.g., via molecular andviscous diffusion) along the flame surface (or diffusionboundary/interface) to generate the diffusion flame. It is noteworthythat the fuel 70 and oxidant 68 may be at a substantially stoichiometricratio along this flame surface (or diffusion boundary/interface), whichmay result in a greater flame temperature (e.g., a peak flametemperature) along this flame surface. The stoichiometric fuel/oxidantratio generally results in a greater flame temperature (e.g., a peakflame temperature), as compared with a fuel-lean or fuel-richfuel/oxidant ratio. As a result, the diffusion flame may besubstantially more stable than a premix flame, because the diffusion offuel 70 and oxidant 68 helps to maintain a stoichiometric ratio (andgreater temperature) along the flame surface. Although greater flametemperatures can also lead to greater exhaust emissions, such as NO_(X)emissions, the disclosed embodiments use one or more diluents to helpcontrol the temperature and emissions while still avoiding any premixingof the fuel 70 and oxidant 68. For example, the disclosed embodimentsmay introduce one or more diluents separate from the fuel 70 and oxidant68 (e.g., after the point of combustion and/or downstream from thediffusion flame), thereby helping to reduce the temperature and reducethe emissions (e.g., NO_(X) emissions) produced by the diffusion flame.

In operation, as illustrated, the compressor section 152 receives andcompresses the exhaust gas 66 from the EG processing system 54, andoutputs a compressed exhaust gas 170 to each of the combustors 160 inthe combustor section 154. Upon combustion of the fuel 60, oxidant 68,and exhaust gas 170 within each combustor 160, additional exhaust gas orproducts of combustion 172 (i.e., combustion gas) is routed into theturbine section 156. Similar to the compressor section 152, the turbinesection 156 includes one or more turbines or turbine stages 174, whichmay include a series of rotary turbine blades. These turbine blades arethen driven by the products of combustion 172 generated in the combustorsection 154, thereby driving rotation of a shaft 176 coupled to themachinery 106. Again, the machinery 106 may include a variety ofequipment coupled to either end of the SEGR gas turbine system 52, suchas machinery 106, 178 coupled to the turbine section 156 and/ormachinery 106, 180 coupled to the compressor section 152. In certainembodiments, the machinery 106, 178, 180 may include one or moreelectrical generators, oxidant compressors for the oxidant 68, fuelpumps for the fuel 70, gear boxes, or additional drives (e.g. steamturbine 104, electrical motor, etc.) coupled to the SEGR gas turbinesystem 52. Non-limiting examples are discussed in further detail belowwith reference to TABLE 1. As illustrated, the turbine section 156outputs the exhaust gas 60 to recirculate along the exhaustrecirculation path 110 from an exhaust outlet 182 of the turbine section156 to an exhaust inlet 184 into the compressor section 152. Along theexhaust recirculation path 110, the exhaust gas 60 passes through the EGprocessing system 54 (e.g., the HRSG 56 and/or the EGR system 58) asdiscussed in detail above.

Again, each combustor 160 in the combustor section 154 receives, mixes,and stoichiometrically combusts the compressed exhaust gas 170, theoxidant 68, and the fuel 70 to produce the additional exhaust gas orproducts of combustion 172 to drive the turbine section 156. In certainembodiments, the oxidant 68 is compressed by an oxidant compressionsystem 186, such as a main oxidant compression (MOC) system (e.g., amain air compression (MAC) system) having one or more oxidantcompressors (MOCs). The oxidant compression system 186 includes anoxidant compressor 188 coupled to a drive 190. For example, the drive190 may include an electric motor, a combustion engine, or anycombination thereof. In certain embodiments, the drive 190 may be aturbine engine, such as the gas turbine engine 150. Accordingly, theoxidant compression system 186 may be an integral part of the machinery106. In other words, the compressor 188 may be directly or indirectlydriven by the mechanical power 72 supplied by the shaft 176 of the gasturbine engine 150. In such an embodiment, the drive 190 may beexcluded, because the compressor 188 relies on the power output from theturbine engine 150. However, in certain embodiments employing more thanone oxidant compressor is employed, a first oxidant compressor (e.g., alow pressure (LP) oxidant compressor) may be driven by the drive 190while the shaft 176 drives a second oxidant compressor (e.g., a highpressure (HP) oxidant compressor), or vice versa. For example, inanother embodiment, the HP MOC is driven by the drive 190 and the LPoxidant compressor is driven by the shaft 176. In the illustratedembodiment, the oxidant compression system 186 is separate from themachinery 106. In each of these embodiments, the compression system 186compresses and supplies the oxidant 68 to the fuel nozzles 164 and thecombustors 160. Accordingly, some or all of the machinery 106, 178, 180may be configured to increase the operational efficiency of thecompression system 186 (e.g., the compressor 188 and/or additionalcompressors).

The variety of components of the machinery 106, indicated by elementnumbers 106A, 106B, 106C, 106D, 106E, and 106F, may be disposed alongthe line of the shaft 176 and/or parallel to the line of the shaft 176in one or more series arrangements, parallel arrangements, or anycombination of series and parallel arrangements. For example, themachinery 106, 178, 180 (e.g., 106A through 106F) may include any seriesand/or parallel arrangement, in any order, of: one or more gearboxes(e.g., parallel shaft, epicyclic gearboxes), one or more compressors(e.g., oxidant compressors, booster compressors such as EG boostercompressors), one or more power generation units (e.g., electricalgenerators), one or more drives (e.g., steam turbine engines, electricalmotors), heat exchange units (e.g., direct or indirect heat exchangers),clutches, or any combination thereof. The compressors may include axialcompressors, radial or centrifugal compressors, or any combinationthereof, each having one or more compression stages. Regarding the heatexchangers, direct heat exchangers may include spray coolers (e.g.,spray intercoolers), which inject a liquid spray into a gas flow (e.g.,oxidant flow) for direct cooling of the gas flow. Indirect heatexchangers may include at least one wall (e.g., a shell and tube heatexchanger) separating first and second flows, such as a fluid flow(e.g., oxidant flow) separated from a coolant flow (e.g., water, air,refrigerant, or any other liquid or gas coolant), wherein the coolantflow transfers heat from the fluid flow without any direct contact.Examples of indirect heat exchangers include intercooler heat exchangersand heat recovery units, such as heat recovery steam generators. Theheat exchangers also may include heaters. As discussed in further detailbelow, each of these machinery components may be used in variouscombinations as indicated by the non-limiting examples set forth inTABLE 1.

Generally, the machinery 106, 178, 180 may be configured to increase theefficiency of the compression system 186 by, for example, adjustingoperational speeds of one or more oxidant compressors in the system 186,facilitating compression of the oxidant 68 through cooling, and/orextraction of surplus power. The disclosed embodiments are intended toinclude any and all permutations of the foregoing components in themachinery 106, 178, 180 in series and parallel arrangements, whereinone, more than one, all, or none of the components derive power from theshaft 176. As illustrated below, TABLE 1 depicts some non-limitingexamples of arrangements of the machinery 106, 178, 180 disposedproximate and/or coupled to the compressor and turbine sections 152,156.

TABLE 1 106A 106B 106C 106D 106E 106F MOC GEN MOC GBX GEN LP HP GEN MOCMOC HP GBX LP GEN MOC MOC MOC GBX GEN MOC HP GBX GEN LP MOC MOC MOC GBXGEN MOC GBX DRV DRV GBX LP HP GBX GEN MOC MOC DRV GBX HP LP GEN MOC MOCHP GBX LP GEN MOC CLR MOC HP GBX LP GBX GEN MOC CLR MOC HP GBX LP GENMOC HTR MOC STGN MOC GEN DRV MOC DRV GEN DRV MOC GEN DRV CLU MOC GEN DRVCLU MOC GBX GEN

As illustrated above in TABLE 1, a cooling unit is represented as CLR, aclutch is represented as CLU, a drive is represented by DRV, a gearboxis represented as GBX, a generator is represented by GEN, a heating unitis represented by HTR, a main oxidant compressor unit is represented byMOC, with low pressure and high pressure variants being represented asLP MOC and HP MOC, respectively, and a steam generator unit isrepresented as STGN. Although TABLE 1 illustrates the machinery 106,178, 180 in sequence toward the compressor section 152 or the turbinesection 156, TABLE 1 is also intended to cover the reverse sequence ofthe machinery 106, 178, 180. In TABLE 1, any cell including two or morecomponents is intended to cover a parallel arrangement of thecomponents. TABLE 1 is not intended to exclude any non-illustratedpermutations of the machinery 106, 178, 180. These components of themachinery 106, 178, 180 may enable feedback control of temperature,pressure, and flow rate of the oxidant 68 sent to the gas turbine engine150. As discussed in further detail below, the oxidant 68 and the fuel70 may be supplied to the gas turbine engine 150 at locationsspecifically selected to facilitate isolation and extraction of thecompressed exhaust gas 170 without any oxidant 68 or fuel 70 degradingthe quality of the exhaust gas 170.

The EG supply system 78, as illustrated in FIG. 3, is disposed betweenthe gas turbine engine 150 and the target systems (e.g., the hydrocarbonproduction system 12 and the other systems 84). In particular, the EGsupply system 78, e.g., the EG extraction system (EGES) 80), may becoupled to the gas turbine engine 150 at one or more extraction points76 along the compressor section 152, the combustor section 154, and/orthe turbine section 156. For example, the extraction points 76 may belocated between adjacent compressor stages, such as 2, 3, 4, 5, 6, 7, 8,9, or 10 interstage extraction points 76 between compressor stages. Eachof these interstage extraction points 76 provides a differenttemperature and pressure of the extracted exhaust gas 42. Similarly, theextraction points 76 may be located between adjacent turbine stages,such as 2, 3, 4, 5, 6, 7, 8, 9, or 10 interstage extraction points 76between turbine stages. Each of these interstage extraction points 76provides a different temperature and pressure of the extracted exhaustgas 42. By further example, the extraction points 76 may be located at amultitude of locations throughout the combustor section 154, which mayprovide different temperatures, pressures, flow rates, and gascompositions. Each of these extraction points 76 may include an EGextraction conduit, one or more valves, sensors, and controls, which maybe used to selectively control the flow of the extracted exhaust gas 42to the EG supply system 78.

The extracted exhaust gas 42, which is distributed by the EG supplysystem 78, has a controlled composition suitable for the target systems(e.g., the hydrocarbon production system 12 and the other systems 84).For example, at each of these extraction points 76, the exhaust gas 170may be substantially isolated from injection points (or flows) of theoxidant 68 and the fuel 70. In other words, the EG supply system 78 maybe specifically designed to extract the exhaust gas 170 from the gasturbine engine 150 without any added oxidant 68 or fuel 70. Furthermore,in view of the stoichiometric combustion in each of the combustors 160,the extracted exhaust gas 42 may be substantially free of oxygen andfuel. The EG supply system 78 may route the extracted exhaust gas 42directly or indirectly to the hydrocarbon production system 12 and/orother systems 84 for use in various processes, such as enhanced oilrecovery, carbon sequestration, storage, or transport to an offsitelocation. However, in certain embodiments, the EG supply system 78includes the EG treatment system (EGTS) 82 for further treatment of theexhaust gas 42, prior to use with the target systems. For example, theEG treatment system 82 may purify and/or separate the exhaust gas 42into one or more streams 95, such as the CO₂ rich, N₂ lean stream 96,the intermediate concentration CO₂, N₂ stream 97, and the CO₂ lean, N₂rich stream 98. These treated exhaust gas streams 95 may be usedindividually, or in any combination, with the hydrocarbon productionsystem 12 and the other systems 84 (e.g., the pipeline 86, the storagetank 88, and the carbon sequestration system 90).

Similar to the exhaust gas treatments performed in the EG supply system78, the EG processing system 54 may include a plurality of exhaust gas(EG) treatment components 192, such as indicated by element numbers 194,196, 198, 200, 202, 204, 206, 208, and 210. These EG treatmentcomponents 192 (e.g., 194 through 210) may be disposed along the exhaustrecirculation path 110 in one or more series arrangements, parallelarrangements, or any combination of series and parallel arrangements.For example, the EG treatment components 192 (e.g., 194 through 210) mayinclude any series and/or parallel arrangement, in any order, of: one ormore heat exchangers (e.g., heat recovery units such as heat recoverysteam generators, condensers, coolers, or heaters), catalyst systems(e.g., oxidation catalyst systems), particulate and/or water removalsystems (e.g., inertial separators, coalescing filters, waterimpermeable filters, and other filters), chemical injection systems,solvent based treatment systems (e.g., absorbers, flash tanks, etc.),carbon capture systems, gas separation systems, gas purificationsystems, and/or a solvent based treatment system, or any combinationthereof. In certain embodiments, the catalyst systems may include anoxidation catalyst, a carbon monoxide reduction catalyst, a nitrogenoxides reduction catalyst, an aluminum oxide, a zirconium oxide, asilicone oxide, a titanium oxide, a platinum oxide, a palladium oxide, acobalt oxide, or a mixed metal oxide, or a combination thereof. Thedisclosed embodiments are intended to include any and all permutationsof the foregoing components 192 in series and parallel arrangements. Asillustrated below, TABLE 2 depicts some non-limiting examples ofarrangements of the components 192 along the exhaust recirculation path110.

TABLE 2 194 196 198 200 202 204 206 208 210 CU HRU BB MRU PRU CU HRU HRUBB MRU PRU DIL CU HRSG HRSG BB MRU PRU OCU HRU OCU HRU OCU BB MRU PRUHRU HRU BB MRU PRU CU CU HRSG HRSG BB MRU PRU DIL OCU OCU OCU HRSG OCUHRSG OCU BB MRU PRU DIL OCU OCU OCU HRSG HRSG BB COND INER WFIL CFIL DILST ST OCU OCU BB COND INER FIL DIL HRSG HRSG ST ST OCU HRSG HRSG OCU BBMRU MRU PRU PRU ST ST HE WFIL INER FIL COND CFIL CU HRU HRU HRU BB MRUPRU PRU DIL COND COND COND HE INER FIL COND CFIL WFIL

As illustrated above in TABLE 2, a catalyst unit is represented by CU,an oxidation catalyst unit is represented by OCU, a booster blower isrepresented by BB, a heat exchanger is represented by HX, a heatrecovery unit is represented by HRU, a heat recovery steam generator isrepresented by HRSG, a condenser is represented by COND, a steam turbineis represented by ST, a particulate removal unit is represented by PRU,a moisture removal unit is represented by MRU, a filter is representedby FIL, a coalescing filter is represented by CFIL, a water impermeablefilter is represented by WFIL, an inertial separator is represented byINER, and a diluent supply system (e.g., steam, nitrogen, or other inertgas) is represented by DIL. Although TABLE 2 illustrates the components192 in sequence from the exhaust outlet 182 of the turbine section 156toward the exhaust inlet 184 of the compressor section 152, TABLE 2 isalso intended to cover the reverse sequence of the illustratedcomponents 192. In TABLE 2, any cell including two or more components isintended to cover an integrated unit with the components, a parallelarrangement of the components, or any combination thereof. Furthermore,in context of TABLE 2, the HRU, the HRSG, and the COND are examples ofthe HE; the HRSG is an example of the HRU; the COND, WFIL, and CFIL areexamples of the WRU; the INER, FIL, WFIL, and CFIL are examples of thePRU; and the WFIL and CFIL are examples of the FIL. Again, TABLE 2 isnot intended to exclude any non-illustrated permutations of thecomponents 192. In certain embodiments, the illustrated components 192(e.g., 194 through 210) may be partially or completed integrated withinthe HRSG 56, the EGR system 58, or any combination thereof. These EGtreatment components 192 may enable feedback control of temperature,pressure, flow rate, and gas composition, while also removing moistureand particulates from the exhaust gas 60. Furthermore, the treatedexhaust gas 60 may be extracted at one or more extraction points 76 foruse in the EG supply system 78 and/or recirculated to the exhaust inlet184 of the compressor section 152.

As the treated, recirculated exhaust gas 66 passes through thecompressor section 152, the SEGR gas turbine system 52 may bleed off aportion of the compressed exhaust gas along one or more lines 212 (e.g.,bleed conduits or bypass conduits). Each line 212 may route the exhaustgas into one or more heat exchangers 214 (e.g., cooling units), therebycooling the exhaust gas for recirculation back into the SEGR gas turbinesystem 52. For example, after passing through the heat exchanger 214, aportion of the cooled exhaust gas may be routed to the turbine section156 along line 212 for cooling and/or sealing of the turbine casing,turbine shrouds, bearings, and other components. In such an embodiment,the SEGR gas turbine system 52 does not route any oxidant 68 (or otherpotential contaminants) through the turbine section 156 for coolingand/or sealing purposes, and thus any leakage of the cooled exhaust gaswill not contaminate the hot products of combustion (e.g., workingexhaust gas) flowing through and driving the turbine stages of theturbine section 156. By further example, after passing through the heatexchanger 214, a portion of the cooled exhaust gas may be routed alongline 216 (e.g., return conduit) to an upstream compressor stage of thecompressor section 152, thereby improving the efficiency of compressionby the compressor section 152. In such an embodiment, the heat exchanger214 may be configured as an interstage cooling unit for the compressorsection 152. In this manner, the cooled exhaust gas helps to increasethe operational efficiency of the SEGR gas turbine system 52, whilesimultaneously helping to maintain the purity of the exhaust gas (e.g.,substantially free of oxidant and fuel).

FIG. 4 is a flow chart of an embodiment of an operational process 220 ofthe system 10 illustrated in FIGS. 1-3. In certain embodiments, theprocess 220 may be a computer implemented process, which accesses one ormore instructions stored on the memory 122 and executes the instructionson the processor 120 of the controller 118 shown in FIG. 2. For example,each step in the process 220 may include instructions executable by thecontroller 118 of the control system 100 described with reference toFIG. 2.

The process 220 may begin by initiating a startup mode of the SEGR gasturbine system 52 of FIGS. 1-3, as indicated by block 222. For example,the startup mode may involve a gradual ramp up of the SEGR gas turbinesystem 52 to maintain thermal gradients, vibration, and clearance (e.g.,between rotating and stationary parts) within acceptable thresholds. Forexample, during the startup mode 222, the process 220 may begin tosupply a compressed oxidant 68 to the combustors 160 and the fuelnozzles 164 of the combustor section 154, as indicated by block 224. Incertain embodiments, the compressed oxidant may include a compressedair, oxygen, oxygen-enriched air, oxygen-reduced air, oxygen-nitrogenmixtures, or any combination thereof. For example, the oxidant 68 may becompressed by the oxidant compression system 186 illustrated in FIG. 3.The process 220 also may begin to supply fuel to the combustors 160 andthe fuel nozzles 164 during the startup mode 222, as indicated by block226. During the startup mode 222, the process 220 also may begin tosupply exhaust gas (as available) to the combustors 160 and the fuelnozzles 164, as indicated by block 228. For example, the fuel nozzles164 may produce one or more diffusion flames, premix flames, or acombination of diffusion and premix flames. During the startup mode 222,the exhaust gas 60 being generated by the gas turbine engine 156 may beinsufficient or unstable in quantity and/or quality. Accordingly, duringthe startup mode, the process 220 may supply the exhaust gas 66 from oneor more storage units (e.g., storage tank 88), the pipeline 86, otherSEGR gas turbine systems 52, or other exhaust gas sources.

The process 220 may then combust a mixture of the compressed oxidant,fuel, and exhaust gas in the combustors 160 to produce hot combustiongas 172, as indicated by block 230 by the one or more diffusion flames,premix flames, or a combination of diffusion and premix flames. Inparticular, the process 220 may be controlled by the control system 100of FIG. 2 to facilitate stoichiometric combustion (e.g., stoichiometricdiffusion combustion, premix combustion, or both) of the mixture in thecombustors 160 of the combustor section 154. However, during the startupmode 222, it may be particularly difficult to maintain stoichiometriccombustion of the mixture (and thus low levels of oxidant and unburntfuel may be present in the hot combustion gas 172). As a result, in thestartup mode 222, the hot combustion gas 172 may have greater amounts ofresidual oxidant 68 and/or fuel 70 than during a steady state mode asdiscussed in further detail below. For this reason, the process 220 mayexecute one or more control instructions to reduce or eliminate theresidual oxidant 68 and/or fuel 70 in the hot combustion gas 172 duringthe startup mode.

The process 220 then drives the turbine section 156 with the hotcombustion gas 172, as indicated by block 232. For example, the hotcombustion gas 172 may drive one or more turbine stages 174 disposedwithin the turbine section 156. Downstream of the turbine section 156,the process 220 may treat the exhaust gas 60 from the final turbinestage 174, as indicated by block 234. For example, the exhaust gastreatment 234 may include filtration, catalytic reaction of any residualoxidant 68 and/or fuel 70, chemical treatment, heat recovery with theHRSG 56, and so forth. The process 220 may also recirculate at leastsome of the exhaust gas 60 back to the compressor section 152 of theSEGR gas turbine system 52, as indicated by block 236. For example, theexhaust gas recirculation 236 may involve passage through the exhaustrecirculation path 110 having the EG processing system 54 as illustratedin FIGS. 1-3.

In turn, the recirculated exhaust gas 66 may be compressed in thecompressor section 152, as indicated by block 238. For example, the SEGRgas turbine system 52 may sequentially compress the recirculated exhaustgas 66 in one or more compressor stages 158 of the compressor section152. Subsequently, the compressed exhaust gas 170 may be supplied to thecombustors 160 and fuel nozzles 164, as indicated by block 228. Steps230, 232, 234, 236, and 238 may then repeat, until the process 220eventually transitions to a steady state mode, as indicated by block240. Upon the transition 240, the process 220 may continue to performthe steps 224 through 238, but may also begin to extract the exhaust gas42 via the EG supply system 78, as indicated by block 242. For example,the exhaust gas 42 may be extracted from one or more extraction points76 along the compressor section 152, the combustor section 154, and theturbine section 156 as indicated in FIG. 3. In turn, the process 220 maysupply the extracted exhaust gas 42 from the EG supply system 78 to thehydrocarbon production system 12, as indicated by block 244. Thehydrocarbon production system 12 may then inject the exhaust gas 42 intothe earth 32 for enhanced oil recovery, as indicated by block 246. Forexample, the extracted exhaust gas 42 may be used by the exhaust gasinjection EOR system 112 of the EOR system 18 illustrated in FIGS. 1-3.

In some embodiments of the SEGR gas turbine system 52, the exhaust gas42 is recirculated and used to cool the combustor section 154 of the gasturbine engine 150. FIG. 5 is a schematic diagram of the combustorsection 154 that includes various features that are shown in detail inFIGS. 6-9. Elements in FIG. 5 in common with those shown in previousfigures are labeled with the same reference numerals. The axialdirection of the combustor 160 is indicated by arrow 294, the radialdirection is indicated by arrow 296, and the circumferential directionis indicated by arrow 298. As shown in FIG. 5, the oxidant compressionsystem 186 generates a compressed oxidant 300 that may be provided tovarious locations at a head end portion 302 of the combustor 160. Fuel70 is provided to the one or more fuel nozzles 164 in the head endportion 302 of the turbine combustor 160. As discussed above, theoxidant 300 and fuel 70 may be mixed prior to injection into thecombustor 160 via one or more premix fuel nozzles, mixed in thecombustion chamber 160 via one or more diffusion flame nozzles, or anycombination thereof. Thus, the fuel nozzles 164 may be diffusionnozzles, pre-mix fuel nozzles, or any combination thereof. Thecompressed oxidant 300 may include air, oxygen, oxygen-enriched air,oxygen-reduced air, or oxygen nitrogen mixtures. In some embodiments,the compressed oxidant 300 may have a concentration of the exhaust gas42 of less than approximately 10 percent, 5 percent, or 1 percent byvolume. As discussed above, a SEGR gas turbine system 52 may recirculatea portion of the exhaust gas 42 (e.g., compressed exhaust gas 170)through the compressor section 152 and at least part of the combustorsection 154 (e.g., one or more combustors 160). In some of theembodiments discussed below, the exhaust gas 42 and/or a relativelyinert gas 304 do not recirculate through the head end portion 302 of thecombustor 160. The compressed exhaust gas 170 and/or the relativelyinert gas 304 from the compressor section 152 may be supplied to aturbine end portion 310 of the combustor 160 rather than to the head endportion 302, thus helping to maintain isolation between the oxidant 300and the inert gas 304. In some embodiments, the inert gas 304 may haveless than approximately 10 percent, 5 percent, or 1 percent by volume ofoxidant 300 (e.g., oxygen (O₂)). One or more fuels 70 may be supplied tothe fuel nozzles 164. For example, the fuel 70 may include, but is notlimited to, a gaseous fuel (e.g., natural gas, process gas, methane,hydrogen, carbon monoxide), a liquid fuel (e.g., light distillates,kerosene, heating oil), or any combination thereof.

The compressor section 152 supplies the inert gas 304 (e.g., nitrogen,carbon dioxide, carbon monoxide, compressed exhaust gas 170) to acompressor discharge casing 305, which encloses at least part of thecombustor 160 of the combustor section 154 (e.g., the combustion chamber168). The inert gas 304 may be substantially inert (e.g., unreactive)relative to the oxidant 300. The combustion chamber 168 is partiallyenclosed by a combustor cap 306 of the head end portion 302, and acombustor liner 308 (e.g., inner wall) along the axis 294 of thecombustor 160. The combustor liner 308 extends in the circumferentialdirection 298 around the combustion chamber 168. The turbine end portion310 of the combustor 160 guides the combustion gases 172 from combustionof the oxidant 300 and the fuel 70 in the downstream direction 312 tothe turbine section 156. In some embodiments, the combustion gases 172that exit the combustor 160 may be substantially free of oxidant 300 andfuel 70, with a concentration of less than approximately 10, 5, 3, 2, or1 percent by volume of oxidant 300 and fuel 70. A flow sleeve 314 (e.g.,intermediate wall) forms a passage 316 about the combustor liner 308that enables a fluid (e.g., inert gas 304 such as exhaust gas 170) toflow along the outside of the combustion chamber 168. The passage 316extends in the circumferential direction 298 around the combustor liner308, and the flow sleeve 314 extends in the circumferential direction298 around the passage 316. In some embodiments, the inert gas 304 is aprimary cooling media for the combustion chamber 168 and/or a heat sinkfor the combustion gases 172.

The passage 316 may be open to the head end portion 302 and to thedischarge casing 305. In some embodiments, a portion of the compressedoxidant 300 enters an oxidant section 318 of the passage 316 in thedownstream direction 312 relative to the combustion gases 172 from thehead end portion 302 toward the turbine section 156. The inert gas 304(e.g., exhaust gas 170) enters a cooling section 320 of the passage 316in an upstream direction 322 relative to the combustion gases 172 fromthe turbine end portion 310 of the combustor 160. A barrier section 324separates the oxidant section 318 from the cooling section 320. Asdiscussed in detail below, the barrier section 324 may include aphysical barrier that at least partially blocks the oxidant 300 and theinert gas 304 from interacting within the passage 316, and/or thebarrier section 324 may include a dynamic barrier. The opposing flows(e.g., oxidant 300 in the downstream direction 312, inert gas 304 in theupstream direction 322) interact at a dynamic barrier to substantiallyblock either flow from passing to the other section (e.g., oxidantsection 318, cooling section 320).

In some embodiments, an extraction sleeve 326 extends circumferentially298 around at least part of the flow sleeve 314 and combustor section154. The extraction sleeve 326 is in fluid communication with the flowsleeve 314, thereby enabling some of the inert gas 304 (e.g., compressedexhaust gas 170) in the flow sleeve 314 to be extracted to an exhaustextraction system 80. The inert gas 304 may be bled into the extractionsleeve 326 to control the flow rate of the inert gas 304 within thepassage 316. As described in some embodiments above, the compressedexhaust gas 170 may be recirculated through the SEGR gas turbine system52 and may be utilized by a fluid injection system 36 for enhanced oilrecovery.

FIG. 6 illustrates a schematic of an embodiment of the combustor 160with the oxidant 300 and the inert gas 304 separated within the passage316 by a dynamic barrier 340. The oxidant 300 and fuel 70 are suppliedto the head end portion 302 and fuel nozzles 164. A controller 342controls the supply of the fuel 70 and the oxidant 300 to the head endportion 302. The controller 342 may control the fuel nozzles 164 toadjust the mixing and distribution of the oxidant 300 and fuel 70 withinthe combustion chamber 168. A portion 344 of the oxidant 300 may besupplied to the passage 316 along the combustion liner 308. Mixing holes346 may direct the oxidant portion 344 into the combustion chamber 168to mix (e.g., uniformly mix) the oxidant 300 and fuel 70 from the fuelnozzles 164, to stabilize a flame 348 (e.g., diffusion flame and/orpremix flame) from the one or more fuel nozzles 164, and/or to shape theflame 348 within the combustion chamber 168. The controller 342 mayadjust the oxidant/fuel mixture injected through the combustor cap 306,and the controller 342 may adjust the oxidant portion 344 suppliedthrough the mixing holes 346 or the passage 316 to control theequivalence ratio for the reaction within the combustion chamber 168. Insome embodiments, the combustor liner 308 may have one or more rows ofmixing holes 346 proximate to the head end portion 302. For example, thecombustor liner 308 may have approximately 1 to 1000, 1 to 500, 1 to100, 1 to 10, or any other number of rows of mixing holes 346 about thecombustor liner 308, wherein each row may include approximately 1 to1000 or more holes 346. In some embodiments, the mixing holes 346 aresymmetrically spaced about the combustor liner 308. In some embodiments,the position, shape, and/or size of the mixing holes 346 may differbased at least in part on spacing from the combustor cap 306. The shapeof the mixing holes 346 may include, but is not limited to, circles,slots, or chevrons, or any combination thereof.

The inert gas 304 enters the flow sleeve 314 from the compressordischarge casing 305 through inlets 350. The inert gas 304 cools thecombustor liner 308 through one or more cooling processes. For example,the inert gas 304 flowing through the inlets 350 may cool the combustorliner 308 opposite the inlets 350 by impingement cooling against theliner 308. The inert gas 304 flowing through the cooling section 320 ofthe passage 316 may cool the liner 308 by convective cooling and/or filmcooling along an outer surface 352. The inert gas 304 may cool an innersurface 354 by flowing through mixing holes 346 and/or dilution holes356 in the combustor liner 308. In some embodiments, the combustor liner308 may have one or more rows of dilution holes 356 downstream (e.g.,arrow 312) of the mixing holes 346. For example, the combustor liner 308may have approximately 1 to 1000, 1 to 500, 1 to 100, 1 to 10, or anyother number of rows of dilution holes 356 about the combustor liner308. In some embodiments, the dilution holes 356 are symmetricallyspaced about the combustor liner 308. As discussed above with the mixingholes 346, the dilution holes 356 may include varying positions, shapes,and/or sizes based at least in part on spacing from the combustor cap306.

In some embodiments, the mixing holes 346 direct the inert gas 304(e.g., exhaust gas 170) into the combustion chamber 168 to mix with theoxidant 300 and the fuel 70 from the fuel nozzles 164, to stabilize theflame 348, to quench the flame 348 and reduce emissions (e.g., NO_(x)emission), and/or to shape the flame 348 within the combustion chamber168. In some embodiments, mixing the oxidant 300 and the fuel 70 may aidbringing the equivalence ratio to approximately 1.0. The mixing holes346 extend through the combustor liner 308 along a flame zone 358. Theflame zone 358 at least partially surrounds the flames 348 within thecombustion chamber 168. Accordingly, the mixing holes 346 may direct afluid (e.g., oxidant 300, inert gas 304) toward the flame 348 to affectthe equivalence ratio of the combustion. The flow rate, velocity, and/ordirection of the fluid (e.g., oxidant 300, inert gas 304) through themixing holes 346 may affect various parameters of the flames 348 in thecombustion chamber 168. For example, the flow rate and velocity of thefluid may affect mixing of the oxidant 300 and the fuel 70 by shapingthe flames 348. In some embodiments, a fluid flow through mixing holes346 angled downstream may form a cooling film (e.g., film cooling) alongthe combustor liner 308.

The dilution holes 356 extend through the combustor liner 308 along adilution zone 360. The dilution zone 360 may be between the flame zone358 and the turbine section 156 connected to the turbine end portion310. The dilution holes 356 may direct the inert gas 304 (e.g., exhaustgas 170) into the combustion chamber 168 to cool the combustion gases172 and/or to dilute reactants (e.g., oxidant 300, fuel 70) near theturbine end section 310. The flow rate, velocity, and/or direction ofthe inert gas 304 through the dilution holes 356 may affect variousparameters of the combustion gases 172. For example, increasing thevelocity of the inert gas 304 may mix the combustion gases 172 toincrease the equivalence ratio and/or to increase a dilution ofunreacted oxidant 300 or fuel 70. Increasing the flow rate of the inertgas 304 may further dilute and cool the combustion gases 172, which mayhelp to reduce emissions such as NO_(x). In some embodiments, thecombustion gases 172 and flames 348 are between approximately 1800° C.to 2200° C. in the flame zone 358. The inert gas 304 cools thecombustion gases 172 to less than approximately 1700° C. at an exit 362of the turbine end portion 310. In some embodiments, the inert gas 304may cool the combustion gases 172 approximately 100° C., 250° C., 500°C., 750° C., or 1000° C. or more through the dilution zone 360. In someembodiments, the dilution holes 356 are staged within the dilution zone360 to enable a desired heat removal from the combustion gases 172, adesired exit temperature profile of the combustion gases 172, or adesired inert gas 304 distribution, or any combination thereof.

The inert gas 304 (e.g., exhaust gas 170) enters the passage 316 andflows in the upstream direction 322 towards the head end portion 302. Insome embodiments, the controller 342 may control one or more valves 364along the flow sleeve 314 and/or the extraction sleeve 326 to controlthe flow rate of the inert gas 304 into the passage 316. As may beappreciated, the inert gas 304 and oxidant 300 may be pressurized to thepressure of the combustion gases 172, so that the inert gas 304 andoxidant 300 may flow into the combustion chamber 168. The oxidantportion 344 enters the passage 316 and flows in the downstream direction312 towards the turbine end portion 310 from the head end portion 302.In some embodiments, the oxidant portion 344 and the inert gas 304interact at the dynamic barrier 340 within the passage 316. The dynamicbarrier 340 is the interaction of the opposing oxidant portion 344 flowand the inert gas 304 flow. At the dynamic barrier 340, the oxidantportion 344 flowing downstream substantially blocks the inert gas 304from flowing upstream beyond the dynamic barrier 340, and the inert gas304 flowing upstream substantially blocks the oxidant portion 344 fromflowing downstream beyond the dynamic barrier 340. The dynamic barrier340 is positioned within the barrier section 324 of the passage 316,separating the oxidant portion 344 from the inert gas 304 within thepassage 316. Accordingly, the oxidant section 318 of the passage 316supplies the oxidant portion 344 substantially free of the inert gas304, and the cooling section 320 of the passage 316 supplies the inertgas 304 substantially free of the oxidant portion 344. The position ofthe dynamic barrier 340 along the passage 316 may be adjustable (e.g.,dynamic) during operation of the combustor 160 based at least in part onparameters (e.g., relative flow rates, pressures, velocities) of theoxidant portion 344 and the inert gas 304 within the passage 316.Adjusting the position of the dynamic barrier 340 affects the relativelengths of the oxidant section 318 and the cooling section 320.

The dynamic barrier 340 may be located within the passage 316 where thepressure of the inert gas 304 is approximately equal to the pressure ofthe oxidant portion 344, or a pressure balance point. For example, thedynamic barrier 340 may be positioned at a first location 366 near thehead end portion 302 if the pressure of the inert gas 304 in the passage316 is approximately equal to the pressure of the oxidant 300 at thehead end portion 302. Positioning the dynamic barrier 340 near the headend portion 302 may reduce the flow of the oxidant portion 344 throughthe mixing holes 346, and increase the flow of the inert gas 304 throughthe mixing holes 346. The dynamic barrier 340 at the first location 366may reduce the concentration of the oxidant 300 in the flame zone 358.The dynamic barrier 340 may be positioned at a second location 368 nearthe turbine end portion 310 of the combustor 160 if the pressure of theoxidant portion 344 in the passage 316 is approximately equal to thepressure of the inert gas 304 in the compressor discharge casing 305.Positioning the dynamic barrier 340 near the turbine end portion 310 mayreduce or eliminate the flow of the inert gas 304 through the mixingholes 346, and increase the flow of the oxidant portion 344 through themixing holes 346. The dynamic barrier 340 at the second location 368 mayincrease the concentration of the oxidant 300 in the flame zone 358. Thepressure balance point, and accordingly the location of the dynamicbarrier 340 within the passage 316 between the oxidant portion 344 andthe inert gas 304, may be controlled by controlling the pressures of theoxidant portion 344 and the inert gas 304 within the passage 316. Thedynamic barrier 340 may be positioned within the passage 316 to controlthe composition of the fluid through the mixing holes 346 and/or thedilution holes 356. For example, the dynamic barrier 340 may bepositioned relative to mixing holes 346 to adjust the oxidant portion344 supplied to the combustion chamber 168, thereby affecting theequivalence ratio of combustion. The dynamic barrier 340 may bepositioned to control the cooling of the combustor liner 308 and thecombustion gases 172 by the inert gas 304 (e.g., exhaust gas 170).Accordingly, the position of the dynamic barrier 340 may control thecomposition of the fluid entering the combustion chamber 168 through thecombustor liner 308, the mix of the oxidant 300 and fuel 70, the shapeof the flames 348, the temperature of the combustion liner 308, thetemperature of the combustion gases 172, emissions (e.g., NO_(x)) in thecombustion gases 172, or any combination thereof.

The controller 342 may control the position of the dynamic barrier 340by controlling the flow of the oxidant portion 344 into the passage 316and controlling the flow of the inert gas 304 (e.g., exhaust gas 170)within the passage 316. In some embodiments, the controller 342 controlsthe flow of the oxidant portion 344 through controlling the pressure ofthe oxidant portion 344 within the head end portion 302 and/or,controlling the flow rate of the oxidant 300 supplied to the fuelnozzles 164. The controller 342 may control the flow of the inert gas304 into the passage 316 by controlling the flow of exhaust gas 42 intothe compressor discharge casing 305, controlling the pressure within thecompressor discharge casing 305, and/or controlling a bleed flow 370through the extraction sleeve 326. The valve 364 connected to theextraction sleeve 326 may control the flow of the inert gas 304 throughthe passage 316. For example, opening the valve 364 may increase thebleed flow 370 and decrease the flow of inert gas 304 through thecoolant section 320, thereby moving the dynamic barrier 340 toward theturbine end portion 310. Closing the valve 364 may decrease the bleedflow 370 to the exhaust extraction system 80 and may increase the flowof inert gas 304 through the coolant section 320 into the combustionchamber 168. Thus, closing the valve 364 may move the dynamic barrier340 toward the head end portion 302. The controller 342 may control theoxidant portion 344 and the inert gas 304 to adjust the dynamic barrier340 within the passage 316 while maintaining the head end portion 302substantially free of the inert gas 304. The controller 342 may adjustthe dynamic barrier 340 within the passage while maintaining thecombustion gases 172 at the turbine end portion 310 substantially freeof oxidant 300. As discussed above, combustion gases 172 with lowconcentrations (e.g., less than approximately 10, 5 or 1 percent oxidant300 by volume) may be recirculated through the combustor as compressedexhaust gas 170 and/or utilized by a fluid injection system 36 forenhanced oil recovery.

FIG. 7 illustrates a schematic of an embodiment of the combustor 160with the oxidant 300 and the inert gas 304 separated within the passage316 by a physical barrier 400 or divider in the barrier section 324 ofthe passage 316. The oxidant 300 may enter the head end portion 302 andthe inert gas 304 may enter the passage 316 as described above with FIG.6. The physical barrier 400 is arranged between the combustor liner 308and the flow sleeve 314, at least partially blocking a fluid flowthrough the passage 316. In some embodiments, the physical barrier 400is a separate component from the combustor liner 308 and the flow sleeve314. For example, the physical barrier 400 may be a fitting (e.g., ring,partial ring, annular wall) about the combustor liner 308. The physicalbarrier 400 may have seals to interface with the combustor liner 308 andthe flow sleeve 314, and to at least partially block fluid communicationbetween the oxidant portion 344 and the inert gas 304. In someembodiments, the physical barrier 400 is connected to or integrallyformed with the combustor liner 308 or the flow sleeve 314. For example,the physical barrier 400 may be a flange disposed circumferentially 298about the combustor liner 308 or within the flow sleeve 314.

In some embodiments, the physical barrier 400 blocks substantially theentire passage of the barrier section 324, thereby blocking the inertgas 304 and oxidant portion 344 from interacting within the passage 316.As shown in FIG. 7, one or more partial physical barriers 402 may bearranged within the passage 316 in addition to a physical barrier 400that blocks substantially all fluid communication between the oxidantportion 344 and the inert gas 304 in the passage 316. The one or morepartial physical barrier 402 may affect the pressure, velocity, and/orflow rate of the fluid (e.g., oxidant portion 344, inert gas 304)entering the combustion chamber 168 through the mixing holes 346 ordilution holes 356 beyond the partial physical barrier 402. For example,a partial physical barrier 402 in the oxidant section 318 between mixingholes 346 may reduce the flow rate or pressure of the oxidant portion344 through the mixing hole 346 downstream (e.g., arrow 312) of thepartial physical barrier 402.

In some embodiments, the partial physical barrier 402 includes passagesor flow guides that restrict or limit fluid communication across thepartial physical barrier 402. A partial physical barrier 402 may affectthe velocity and/or pressure of the oxidant 300 or the inert gas 304flowing around the partial physical barrier 402. Accordingly, one ormore partial physical barriers 402 may be utilized to control a positionof the dynamic barrier 340 discussed above. For example, a partialphysical barrier 402 in the cooling section 320 upstream (e.g., arrow322) of the dilution holes 356 may reduce the pressure of the inert gas304 so that the dynamic barrier 340 is positioned proximate to themixing holes 346 or among the mixing holes 346 for a desirableequivalence ratio rather than proximate to the head end portion 302. Insome embodiments, a partial physical barrier 402 may be utilized inaddition to controlling the flows of the oxidant portion 344 and theinert gas 304 into the passage 316 to form the dynamic barrier 340.

As described above, the controller 342 may control the flow of oxidant300 to the head end portion 302, and may control the flow of the inertgas 304 (e.g., exhaust gas 170) into the passage 316 and the extractionsleeve 326. In some embodiments, the controller 342 controls thedistribution of a first fuel 404 to a first set 406 of fuel nozzles 164and controls the distribution of a second fuel 408 to a second set 410of fuel nozzles 164. Each set 406, 410 may include one or more fuelnozzles 164. For example, the first set 406 may include a center fuelnozzle, and the second set 410 may include perimeter fuel nozzles (e.g.,approximately 1 to 10 nozzles) as shown in FIG. 7. In some embodiments,a first set 406 may be a pilot fuel nozzle, and the first fuel 404 mayhave a higher heating value than the second fuel 408 injected by thesecond set 410 of perimeter fuel nozzles. As may be appreciated, thefirst set 406 of fuel nozzles may be used at startup of the gas turbineengine 150, and the flow rate of the first fuel 404 may be reduced aftera period of operation of the gas turbine engine 150. The first set 406may improve the flame stability of the second set 410. In someembodiments, oxidant 300 injected through the combustor cap 306 aboutthe first set 406 of fuel nozzles 164 may shield and/or stabilize theflame 348 of the first set 406. The first fuel 404 injected from thefirst set 406 of fuel nozzles 164 may adjust a rate of combustion,thereby affecting the equivalence ratio. In some embodiments, the secondset 410 of fuel nozzles 164 provides the second fuel 408 that isutilized primarily for a steady-state operation of the gas turbineengine 150.

The first and second fuels 404, 408 may include, but are not limited tonatural gas, liquefied natural gas (LNG), syngas, carbon monoxide,hydrogen, methane, ethane, propane, butane, naphtha, kerosene, dieselfuel, light distillates, heating oil, ethanol, methanol, biofuel, or anycombination thereof. In some embodiments, the first and the second fuels404, 408 are the same fuel, and the controller 342 differentiallycontrols the distribution to the first and second sets 406, 410 of fuelnozzles. It may be appreciated that while two fuels 404, 408 and twosets 406, 410 of fuel nozzles 164 are described above, some embodimentsof the combustor 160 may have 1, 2, 3, 4, 5, or more sets of fuelnozzles 164 to inject 1, 2, 3, 4, 5, or more fuels 70 into thecombustion chamber 168.

In some embodiments, the second set 410 of fuel nozzles 164 (e.g.,perimeter fuel nozzles) may provide more than approximately 70, 80, 90,or 95 percent of the total fuel injected into the combustor 160. Thecontroller 342 may control the second set 410 of fuel nozzles 164 toadjust the bulk combustor equivalence ratio, and may control the firstset 406 of fuel nozzles 164 (e.g., center fuel nozzle) to fine tune theequivalence ratio. For example, the first set 406 of fuel nozzles 164may provide less than approximately 30, 20, 10, or 5 percent of thetotal fuel injected into the combustor 160. Controlling the flow rate ofthe first fuel 404 through the first set 406 of fuel nozzles 164 therebyenables the controller 342 to adjust (e.g., fine tune) the equivalenceratio with relatively small adjustments. As an example, where the firstset 406 provides approximately 20 percent of the total fuel and thesecond set 410 provides approximately 80 percent of the total fuel,adjusting (e.g., increasing, decreasing) the first fuel 404 by 10percent adjusts the total fuel in the combustor 160 by approximately 2percent.

FIG. 8 illustrates a cross-section of an embodiment of the combustor 160of FIG. 7, taken along line 8-8. In some embodiments, the fuel nozzles164 may be arranged in a circular arrangement, such as the second set410 arranged circumferentially 298 around the first set 406. As may beappreciated, the cross-section of the combustor 160 is not limited to besubstantially circular, and the combustor liner 308, the flow sleeve314, and the extraction sleeve 326 may have other shapes (e.g.,rectangular, ovoid). The partial physical barrier 402 is arrangedbetween the combustor liner 308 and the flow sleeve 314, within thepassage 316. In some embodiments, portions 430 of the partial physicalbarrier 402 interface with the combustor liner 308 and the flow sleeve314 at points about the passage 316, and have openings 432 (e.g., flowguides) that enable restricted fluid communication about the partialphysical barrier 402. In some embodiments, liner openings 438 may liealong the combustor liner 308, sleeve openings 440 may lie along theflow sleeve 314, or interior openings 442 may lie through the partialphysical barrier 40 (e.g., holes, slots, etc.) between the liner 308 andthe flow sleeve 314. In some embodiments, the partial physical barrier402 may interface with one of the combustor liner 308 or the flow sleeve314, permitting fluid (e.g., oxidant portion 344, inert gas 304) to passalong the other of the combustor liner 308 or the flow sleeve 314 aroundthe partial physical barrier 402.

FIG. 9 illustrates an embodiment of the combustor 160 of FIG. 7, takenalong line 8-8, where the partial physical barrier 402 has anothergeometry. Protrusions 434 of the partial physical barrier 402 from thecombustor liner 308 or the flow sleeve 314 partially surround thecombustor liner 308, thereby partially blocking the flow of the oxidantportion 344 or inert gas 304 at some points about the combustor liner308. The openings 432 may extend across the passage 316 at other pointsabout the combustor liner 308, thereby enabling a substantiallyunrestricted flow of the oxidant portion 344 or the inert gas 304 aroundthe partial physical barrier 402. In some embodiments, the protrusions434 of one or more partial physical barriers 402 may direct the fluidsin the passage 316 in a desired circumferential direction 298 about anaxis 436 of the combustor 160. Accordingly, one or more partial physicalbarriers 402 may provide a rotational component (e.g., swirl) to theflow of the oxidant portion 344 or the inert gas 304 through the passage316. In some embodiments, the one or more partial physical barriers 402affect the pressure, velocity, and/or flow rate of the oxidant portion344 or the inert gas 304, which may cause the dynamic barrier 340 toform at a desired position along the passage 316. Presently contemplatedembodiments of the partial physical barrier 402 may include othergeometries of openings 432 and protrusions 434 to at least partiallyblock the passage 316 between the combustor liner 308 and the flowsleeve 314.

The SEGR gas turbine systems 52 and combustors 160 described above maysupply the oxidant 300 and fuel 70 to the combustor 160 at a head endportion 302, and supply an inert gas 304 (e.g., compressed exhaust gas170) to the combustor 160 at a turbine end portion 310 for cooling thecombustor liner 308 and combustion gases 172. In some embodiments, theinert gas 304 may cool the combustion gases 172 to reduce emissions,such as NO_(x). In some embodiments, the combustor 160 may havedifferentially supplied and controlled sets of fuel nozzles 164, inwhich the oxidant 300 and fuels 404, 408 flow in the downstreamdirection 312 from the head end portion 302. The inert gas 304 (e.g.,compressed exhaust gas 170) is supplied through the passage 316 at theturbine end portion 310 to cool the combustor liner 308 and thecombustion gases 172. The inert gas 304 flows in the upstream direction312 through the passage 316, which may be substantially the oppositedirection of the oxidant portion 342 through the passage 316. Theoxidant 300 and the inert gas 304 may not mix upstream (e.g., arrow 322)of the flame 348 (e.g., in the head end portion 302). In someembodiments, the oxidant 300 flows from the fuel nozzles 164, flowsthrough the combustor cap 306, and/or flows through the mixing holes 346to improve a distribution and/or concentration of oxidant 300 in theflame zone 360. In turn, the improved distribution of oxidant 300 helpsto increase the efficiency of combustion, thereby affecting theequivalence ratio. For example, the improved distribution of the oxidant300 flow may help provide substantially stoichiometric combustion. Theinert gas 304 may be a heat sink for the combustor liner 308 and/orcombustion gases 172. Reducing the temperature of the combustion gases172 may reduce emissions, such as NO_(x). The passage 316 between thecombustor liner 308 and the flow sleeve 314 may have one or morephysical barriers 400 and/or a dynamic barrier 340 between the oxidantportion 344 and the inert gas 304. The positions of the one or morephysical barriers 400 and/or the dynamic barrier 340 within the passage316 may be adjusted among various embodiments, based at least in part onthe flows of the oxidant portion 300, the inert gas 304, the equivalenceratio, and other factors.

Separating the oxidant 300 from the inert gas 304 (e.g., compressedexhaust gas 170) upstream of the flame zone 358 within the combustionchamber 168 may increase the flame stability and completeness ofcombustion. The fuel nozzles 164 may also be controlled to adjust theequivalence ratio. Controlling the fuel nozzles 164 and/or isolating theoxidant 300 from the inert gas 304 at desired points in the combustor160 may affect the equivalence ratio. Adjusting the equivalence ratio toapproximately 1.0 (e.g., between 0.95 and 1.05) may reduce theconcentrations of oxidant 300, fuel 70, and/or other components (e.g.,nitrogen oxides, water) within the exhaust gases 42 of a SEGR gasturbine system 52. In some embodiments, adjusting the equivalence ratioto approximately 1.0 may increase the concentration of carbon dioxidethat may be utilized in an enhanced oil recovery system 18. The exhaustgas 42, or the carbon dioxide extracted from the exhaust gas 42, may beutilized by a fluid injection system 36 for enhanced oil recovery.

This written description uses examples to disclose the invention,including the best mode, and also to enable any person skilled in theart to practice the invention, including making and using any devices orsystems and performing any incorporated methods. The patentable scope ofthe invention is defined by the claims, and may include other examplesthat occur to those skilled in the art. Such other examples are intendedto be within the scope of the claims if they have structural elementsthat do not differ from the literal language of the claims, or if theyinclude equivalent structural elements with insubstantial differencesfrom the literal languages of the claims.

Additional Embodiments

The present embodiments provide a system and method for controllingcombustion and emissions in a gas turbine engine with exhaustrecirculation. It should be noted that any one or a combination of thefeatures described above may be utilized in any suitable combination.Indeed, all permutations of such combinations are presentlycontemplated. By way of example, the following clauses are offered asfurther description of the present disclosure:

Embodiment 1

A system having a turbine combustor with a combustor liner disposedabout a combustion chamber and a head end upstream of the combustionchamber relative to a downstream direction of a flow of combustion gasesthrough the combustion chamber. The head end is configured to direct anoxidant flow and a first fuel flow toward the combustion chamber. Theturbine combustor also includes a flow sleeve disposed at an offsetabout the combustor liner to define a passage configured to direct a gasflow toward the head end and configured to direct a portion of theoxidant flow toward a turbine end of the turbine combustor. The gas flowincludes a substantially inert gas. The turbine combustor also includesa barrier within the passage, and the barrier is configured to block theportion of the oxidant flow toward the turbine end and to is configuredto block the gas flow toward the head end within the passage

Embodiment 2

The system of embodiment 1, wherein the oxidant flow and the first fuelflow are configured to substantially stoichiometrically combust in thecombustion chamber.

Embodiment 3

The system of any preceding embodiment, wherein the head end includes afirst fuel nozzle configured to direct the first fuel flow into thecombustion chamber, and a second fuel nozzle configured to direct asecond fuel flow into the combustion chamber, wherein the first fuelnozzle is controlled separately from the second fuel nozzle.

Embodiment 4

The system of any preceding embodiment, wherein the gas flow includes anexhaust gas having less than approximately 5 percent by volume of theoxidant or the first fuel.

Embodiment 5

The system of any preceding embodiment, wherein the barrier includes aphysical barrier configured to extend across the passage and to separatethe passage into an oxidant section and a cooling section.

Embodiment 6

The system of any preceding embodiment, wherein the barrier includes adynamic barrier configured to separate the passage into an oxidantsection and a cooling section. The dynamic barrier includes a fluidinterface between the portion of the oxidant flow and the gas flow, anda position of the dynamic barrier is controlled based at least in parton a pressure difference between the portion of the oxidant flow and thegas flow.

Embodiment 7

The system of embodiment 6, wherein the barrier includes multiple flowguides configured to restrict the passage at the dynamic barrier.

Embodiment 8

The system of any preceding embodiment, wherein the flow sleeve iscoupled to a bleed passage configured to direct a portion of the gasflow into the bleed passage.

Embodiment 9

The system of any preceding embodiment, wherein the gas flow isconfigured to cool the combustor liner, and the gas flow is configuredto dilute and to cool the flow of combustion gases in the turbinecombustor.

Embodiment 10

The system of any preceding embodiment, wherein the combustor linerincludes multiple mixing holes and multiple dilution holes. The multiplemixing holes are configured to direct at least one of the oxidant flowand the gas flow into the combustion chamber. The multiple dilutionholes are configured to direct the gas flow into the combustion chamber.

Embodiment 11

The system of any preceding embodiment, wherein the system includes agas turbine engine having the turbine combustor, a turbine driven by thecombustion gases from the turbine combustor and that outputs the exhaustgas, and an exhaust gas compressor driven by the turbine. The exhaustgas compressor is configured to compress and to rout the exhaust gas tothe turbine combustor.

Embodiment 12

The system of embodiment 11, wherein the gas turbine engine is astoichiometric exhaust gas recirculation (SEGR) gas turbine engine.

Embodiment 13

The system of embodiment 11 or 12, wherein the system includes anexhaust gas extraction system coupled to the gas turbine engine, and ahydrocarbon production system coupled to the exhaust gas extractionsystem.

Embodiment 14

A system includes a turbine combustor having a combustor liner disposedabout a combustion chamber and a flow sleeve disposed at an offset aboutthe combustor liner to define a passage. The passage includes an oxidantsection configured to direct an oxidant in a first direction, whereinthe oxidant is configured to react with a first fuel in the combustionchamber to produce combustion gases. The passage also includes a coolingsection configured to direct an inert gas in a second directionsubstantially opposite to the first direction, wherein the inert gas isconfigured to cool the combustor liner and the combustion gases in thecombustion chamber. The passage also includes a barrier section betweenthe oxidant section and the cooling section, wherein the barrier sectionis configured to substantially separate the oxidant in the oxidantsection from the inert gas in the cooling section.

Embodiment 15

The system of embodiment 14, wherein the system includes a controllerconfigured to control a ratio between the oxidant and the first fuel inthe combustion chamber.

Embodiment 16

The system of embodiment 15, wherein the system includes a first fuelnozzle configured to inject the first fuel into the combustion chamber.The controller is configured to control one or more flows through thefirst fuel nozzle to adjust a first ratio between the oxidant and thefirst fuel in the combustion chamber.

Embodiment 17

The system of embodiment 16, wherein the system includes a second fuelnozzle configured to inject a second fuel into the combustion chamber,wherein the controller is configured to control one or more flowsthrough the second fuel nozzle to adjust a second ratio between theoxidant and the second fuel in the combustion chamber.

Embodiment 18

The system of embodiment 14, 15, 16, or 17 wherein the inert gasincludes an exhaust gas having less than approximately 5 percent byvolume of the oxidant or the first fuel.

Embodiment 19

The system of embodiment 14, 15, 16, 17, or 18, wherein the systemincludes a controller configured to control a first flow of the oxidantinto the oxidant section, a second flow of the inert gas into thecooling section, and a position of the barrier section within thepassage based at least in part on controlling the first flow, the secondflow, or any combination thereof.

Embodiment 20

The system of embodiment 14, 15, 16, 17, 18, or 19, wherein the passageincludes a physical barrier that at least partially extends between thecombustor liner and a flow sleeve.

Embodiment 21

The system of embodiment 14, 15, 16, 17, 18, 19, or 20, wherein theoxidant section includes multiple mixing holes configured to direct theoxidant into the combustion chamber to mix with the first fuel, toincrease a concentration of oxidant in the combustion chamber, or toraise a temperature of a reaction with the first fuel, or anycombination thereof.

Embodiment 22

The system of embodiment 14, 15, 16, 17, 18, 19, 20, or 12, wherein thecoolant section includes multiple dilution holes configured to direct afirst portion of the inert gas into the combustion chamber to cool thecombustor liner, to cool the combustion gases in the combustion chamber,or to reduce emissions of the combustion gases, or any combinationthereof

Embodiment 23

The system of embodiment 22, wherein the coolant section includesmultiple mixing holes configured to direct a second portion of the inertgas into the combustion chamber to mix with the oxidant and the firstfuel, to quench a reaction of the oxidant and the first fuel, or toreduce emissions of the combustion gases, or any combination thereof.

Embodiment 24

A method including injection an oxidant and a fuel into a combustionchamber from a head end of a turbine combustor, combusting the oxidantand the fuel in the combustion chamber to provide substantiallystoichiometric combustion, and cooling the combustion chamber with anexhaust gas flow. The exhaust gas flow is directed upstream from aturbine end of the turbine combustor toward the head end along a passagedisposed about the combustion chamber. The method also includes blockingthe exhaust gas flow within the passage with a barrier, wherein thebarrier includes a dynamic barrier, a physical barrier, or anycombination thereof.

Embodiment 25

The method of embodiment 24, including controlling an equivalence ratioto provide the substantially stoichiometric combustion based at least inpart on controlling at least one of the oxidant and the fuel injectedinto the combustion chamber through one or more fuel nozzles.

Embodiment 26

The method of embodiment 25, including adjusting the equivalence ratioby controlling a first ratio of the oxidant and the fuel injectedthrough a center fuel nozzle of the one or more fuel nozzles whilemaintaining a second ratio of the oxidant and the fuel injected throughperimeter fuel nozzles of the one or more fuel nozzles.

Embodiment 27

The method of embodiment 25, including adjusting the equivalence ratioby controlling the exhaust gas flow into the combustion chamber throughmixing holes of the passage, dilution holes of the passage, or anycombination thereof.

Embodiment 28

The method of embodiment 24, 25, 26, or 27, including reducing emissionsof the combustion gases by diluting the combustion gases in thecombustion chamber with the exhaust gas flow, cooling the combustiongases, or any combination thereof.

Embodiment 29

The method of embodiment 24, 25, 26, 27, or 28, including bleeding aportion of the exhaust gas flow from the passage to control the coolingof the combustion chamber.

Embodiment 30

The method of embodiment 24, 25, 26, 27, 28, or 29, includingcontrolling the dynamic barrier in the passage by controlling a portionof the oxidant in the passage, the exhaust gas flow in the passage, orany combination thereof, wherein the dynamic barrier includes aninterface with the oxidant and the exhaust gas flow.

1. A system comprising: a turbine combustor comprising: a combustorliner disposed about a combustion chamber; a head end upstream of thecombustion chamber relative to a downstream direction of a flow ofcombustion gases through the combustion chamber, wherein the head end isconfigured to direct an oxidant flow and a first fuel flow toward thecombustion chamber; a flow sleeve disposed at an offset about thecombustor liner to define a passage, wherein the passage is configuredto direct a gas flow toward the head end and to direct a portion of theoxidant flow toward a turbine end of the turbine combustor, wherein thegas flow comprises a substantially inert gas; and a barrier within thepassage, wherein the barrier is configured to block the portion of theoxidant flow toward the turbine end and to block the gas flow toward thehead end within the passage.
 2. The system of claim 1, wherein the headend comprises a first fuel nozzle configured to direct the first fuelflow into the combustion chamber, and a second fuel nozzle configured todirect a second fuel flow into the combustion chamber, wherein the firstfuel nozzle is controlled separately from the second fuel nozzle.
 3. Thesystem of claim 1, wherein the gas flow comprises an exhaust gas,wherein the exhaust gas comprises less than approximately 5 percent byvolume of the oxidant or the first fuel.
 4. The system of claim 1,wherein the barrier comprises a physical barrier configured to extendacross the passage, wherein the physical barrier is configured toseparate the passage into an oxidant section and a cooling section. 5.The system of claim 1, wherein the barrier comprises a dynamic barrierconfigured to separate the passage into an oxidant section and a coolingsection, wherein the dynamic barrier comprises a fluid interface betweenthe portion of the oxidant flow and the gas flow, and a position of thedynamic barrier is controlled based at least in part on a pressuredifference between the portion of the oxidant flow and the gas flow. 6.The system of claim 5, wherein the barrier comprises a plurality of flowguides configured to restrict the passage at the dynamic barrier.
 7. Thesystem of claim 1, wherein the combustor liner comprises a plurality ofmixing holes and a plurality of dilution holes, wherein the plurality ofmixing holes is configured to direct at least one of the oxidant flowand the gas flow into the combustion chamber, and the plurality ofdilution holes is configured to direct the gas flow into the combustionchamber.
 8. The system of claim 1, comprising a gas turbine enginehaving the turbine combustor, a turbine driven by the combustion gasesfrom the turbine combustor and that outputs an exhaust gas, and anexhaust gas compressor driven by the turbine, wherein the exhaust gascompressor is configured to compress and to route the exhaust gas to theturbine combustor.
 9. The system of claim 8, wherein the gas turbineengine is a stoichiometric exhaust gas recirculation (SEGR) gas turbineengine.
 10. The system of claim 8, comprising an exhaust gas extractionsystem coupled to the gas turbine engine, and a hydrocarbon productionsystem coupled to the exhaust gas extraction system.
 11. A systemcomprising: a turbine combustor comprising: a combustor liner disposedabout a combustion chamber; and a flow sleeve disposed at an offsetabout the combustor liner to define a passage, wherein the passagecomprises: an oxidant section configured to direct an oxidant in a firstdirection, wherein the oxidant is configured to react with a first fuelin the combustion chamber to produce combustion gases; a cooling sectionconfigured to direct an inert gas in a second direction substantiallyopposite to the first direction, wherein the inert gas is configured tocool the combustor liner and the combustion gases in the combustionchamber; and a barrier section between the oxidant section and thecooling section, wherein the barrier section is configured tosubstantially separate the oxidant in the oxidant section from the inertgas in the cooling section.
 12. The system of claim 11, comprising acontroller configured to control a ratio between the oxidant and thefirst fuel in the combustion chamber.
 13. The system of claim 12,comprising a first fuel nozzle configured to inject the first fuel intothe combustion chamber, wherein the controller is configured to controlone or more flows through the first fuel nozzle to adjust a first ratiobetween the oxidant and the first fuel in the combustion chamber. 14.The system of claim 13, comprising a second fuel nozzle configured toinject a second fuel into the combustion chamber, wherein the controlleris configured to control one or more flows through the second fuelnozzle to adjust a second ratio between the oxidant and the second fuelin the combustion chamber.
 15. The system of claim 11, wherein the inertgas comprises an exhaust gas, wherein the exhaust gas comprises lessthan approximately 5 percent by volume of the oxidant or the first fuel.16. The system of claim 11, comprising a controller configured tocontrol a first flow of the oxidant into the oxidant section, a secondflow of the inert gas into the cooling section, and a position of thebarrier section within the passage based at least in part on controllingthe first flow, the second flow, or any combination thereof.
 17. Thesystem of claim 11, wherein the passage comprises a physical barrierthat at least partially extends between the combustor liner and the flowsleeve.
 18. The system of claim 11, wherein the oxidant sectioncomprises a plurality of mixing holes configured to direct the oxidantinto the combustion chamber to mix with the first fuel, to increase aconcentration of oxidant in the combustion chamber, or to raise atemperature of a reaction with the first fuel, or any combinationthereof.
 19. The system of claim 11, wherein the coolant sectioncomprises a plurality of dilution holes is configured to direct a firstportion of the inert gas into the combustion chamber to cool thecombustor liner, to cool the combustion gases in the combustion chamber,or to reduce emissions of the combustion gases, or any combinationthereof.
 20. A method comprising: injecting an oxidant and a fuel into acombustion chamber from a head end of a turbine combustor; combustingthe oxidant and the fuel in the combustion chamber to providesubstantially stoichiometric combustion; cooling the combustion chamberwith an exhaust gas flow, wherein the exhaust gas flow is directedupstream from a turbine end of the turbine combustor toward the head endalong a passage disposed about the combustion chamber; and blocking theexhaust gas flow within the passage with a barrier, wherein the barriercomprises a dynamic barrier, a physical barrier, or any combinationthereof.
 21. The method of claim 20, comprising controlling anequivalence ratio to provide the substantially stoichiometric combustionbased at least in part on controlling at least one of the oxidant andthe fuel injected into the combustion chamber through one or more fuelnozzles.
 22. The method of claim 21, comprising adjusting theequivalence ratio by controlling a first ratio of the oxidant and thefuel injected through a center fuel nozzle of the one or more fuelnozzles while maintaining a second ratio of the oxidant and the fuelinjected through perimeter fuel nozzles of the one or more fuel nozzles.23. The method of claim 21, comprising adjusting the equivalence ratioby controlling the exhaust gas flow into the combustion chamber throughmixing holes of the passage, dilution holes of the passage, or anycombination thereof.
 24. The method of claim 20, comprising bleeding aportion of the exhaust gas flow from the passage to control the coolingof the combustion chamber.
 25. The method of claim 20, comprisingcontrolling the dynamic barrier in the passage by controlling a portionof the oxidant in the passage, the exhaust gas flow in the passage, orany combination thereof, wherein the dynamic barrier comprises aninterface with the oxidant and the exhaust gas flow.